US Crude Oil Exports, Explained

The United States exported about 4.0 million barrels per day of crude oil in 2025, according to the EIA, down 3 percent from 2024 and the first annual decline since 2021, even though domestic production rose to a record 13.6 million b/d. The country still imports more crude than it ships out, 2.2 million b/d net in 2025, but it is a net exporter of crude and refined products combined, by about 2.85 million b/d.

That paragraph contains the three numbers most export stories get tangled: gross crude exports, net crude imports, and net trade in all petroleum. The sections below separate them, show who buys American crude and why the buyer list changed in 2025, explain the price signal that pulls barrels toward the coast, and compare the weekly, monthly, and annual data series so a single week's print is not mistaken for a trend. Every figure is from EIA publications or official records checked on October 22, 2026, listed at the end.

From 47,000 barrels a day to 4 million: the record, year by year

For four decades crude exports were restricted. The Federal Reserve Bank of Kansas City's history traces the ban to the Energy Policy and Conservation Act of 1975, passed during the oil crises, and notes that by 2015 fears of persistent domestic price discounts in the shale boom drove calls to lift it. Congress did so in the Consolidated Appropriations Act, 2016, Public Law 114-113, approved December 18, 2015. The annual EIA series shows what followed.

Source: EIA, U.S. Exports of Crude Oil, annual, thousand barrels per day (checked October 22, 2026). Notes by PetroEyes; the 2025 decline is as described in EIA Today in Energy, March 10, 2026.

The EIA describes 2025 exports as 85 times the 2011 level. The more useful comparison for today is against production: 3.96 million b/d of exports against 13.6 million b/d of output means roughly 29 percent of domestic crude production left the country as crude in 2025, a PetroEyes ratio from the two EIA figures. The rest was refined at home or went into storage.

Notice also what the table does not show: a straight line. Exports rose in 2020 while world demand collapsed, then fell in 2021 while demand recovered. The export volume is a residual of the domestic balance, not a direct reading of global demand, which is why the next section matters.

Net importer and net exporter at the same time

Two EIA series answer two different questions, and headlines regularly swap them. Net imports are imports minus exports; a negative value means net exports.

Source: EIA, U.S. Net Imports of Crude Oil and U.S. Net Imports of Crude Oil and Petroleum Products, annual (checked October 22, 2026).

In crude alone, the US has remained a net importer every year in the table, though the gap has shrunk from 6.9 million b/d in 2015 to 2.2 million in 2025. In crude and products together, the balance turned negative in 2020 and the net export position has widened every year since, to 2.85 million b/d in 2025. For context on the size of the shift, the same series showed net imports of 12.5 million b/d in 2005.

How can both be true? The US imports crude, much of it heavier grades that suit its complex Gulf Coast and Midwest refineries, and exports refined gasoline, diesel, propane, and other products in large volumes. The imports side of that trade, including why Canada supplies most of it, is covered in US oil imports by country. The practical rule: when someone says the US is "energy independent" in oil, ask whether they mean crude or total petroleum, and net or gross. Only one of the four combinations supports the claim.

Who buys American crude, and what changed in 2025

The EIA's March 10, 2026 analysis of the 2025 data describes the buyer map in two regions and a handful of countries. The table collects the figures it reports.

Source: EIA Today in Energy, "Annual U.S. crude oil exports decrease for first time since 2021," March 10, 2026 (checked October 22, 2026). These are the changes as the EIA described them in March; the annual destination series has been revised since, and the current figures are in the full buyer list further down this page.

Two of those lines carry a story worth knowing. Europe became the top destination in 2023, which the EIA links to the effects of the war in Ukraine and to the inclusion of West Texas Intermediate in Dated Brent, the North Sea price assessment that sets the value of much of the world's crude. Once WTI cargoes delivered to Europe could set the benchmark, American light sweet crude became part of the European pricing system itself rather than an occasional import. That is the institutional link behind the WTI-Brent spread.

Nigeria is the other. A country that is itself an OPEC producer more than doubled its imports of US crude because the 650,000 b/d Dangote refinery, which began processing crude in January 2024 and reached its design capacity in February 2026 according to the EIA, kept buying US barrels as it raised throughput. It is a reminder that crude flows follow refinery configuration and price, not producer-consumer labels. The China figure is the mirror image: an 89 percent drop for what had been the second-largest buyer two years earlier shows how quickly a destination can disappear when relative prices or trade conditions shift.

The full buyer list, from the revised annual data

The March summary describes changes. The EIA's annual series of crude exports by destination, which assigns every barrel to a country, shows the whole list, and it has been revised since March, as trade data usually are. In the version checked on October 28, 2026, ten countries took 3,040 thousand b/d of the 3,961 thousand exported in 2025, or 76.7 percent. The Netherlands alone took 862 thousand b/d, 21.8 percent of all US crude exports, nearly as much as the next two, South Korea and Canada, put together (883 thousand).

Set against the March description, the revised file keeps the direction of every change and moves several of the sizes. The United Kingdom fell from 287 to 191 thousand b/d, a drop of 96 thousand or 33.4 percent, rather than the more than 100,000 first reported. Singapore fell 72.1 percent, from 244 to 68, rather than 75. The Netherlands rose by 72 thousand, India by 95 and Japan by 77, from 23 to 100. China, at 216 thousand b/d in 2024 and 23 in 2025, is still down 89.4 percent, and Nigeria went from 43 to 113. None of that changes the story; it changes which numbers to quote. A figure for a single country in a single year should come from the current annual file, with the date it was checked, because a press summary is frozen on the day it was written and the series behind it is not.

Three readings of the list are worth carrying away. First, concentration rose: the five largest buyers took 57.5 percent of exports in 2025, up from 51.8 percent in 2023, while the number of countries recorded as receiving any US crude fell from 41 to 37. Second, Asia shrank by less than the two headline names suggest. China and Singapore together took 369 thousand b/d less than in 2024, while South Korea, India, Thailand and Japan together took 243 thousand more (Taiwan was down 5), so the five together still took 1,287 thousand b/d in 2025, even as China, the largest Asian buyer of 2023, nearly vanished from the list and Singapore lost almost three-quarters of its volume. Third, a destination in this series is where the customs record says the cargo was going, not necessarily where the crude was refined. A large total for a trading and refining hub can include barrels that are stored, blended or moved on, so a country ranking is a map of first deliveries rather than of final consumption.

Canada, in both directions

The third name on the list surprises people. Canada is by far the largest source of US crude imports, 3,910 thousand b/d in 2025 in the EIA's annual imports data, about 63 percent of the total, and it was also the third-largest buyer of US crude exports, at 378 thousand b/d. The two flows are not netted anywhere in the trade statistics: each is counted gross, in its own series. Exports to Canada were about a tenth of imports from Canada, 9.7 percent, so the balance runs heavily one way, but the two-way trade is real and has been in the data every year of the table above. The inbound side, including which refining districts take the Canadian barrels, is set out in the imports guide, and the heavy Canadian grade that dominates it is covered in the WCS-WTI differential explainer. The EIA series records volumes, not reasons, so this page does not try to say which refineries took the exported barrels.

The arbitrage that pulls barrels to the coast

A barrel leaves the country when it is worth more delivered abroad than sold at home, after paying to move it. The rough signal is the gap between Brent, the international benchmark, and WTI, the inland US benchmark priced at Cushing, Oklahoma (see the Cushing delivery point explainer). The spread has to cover pipeline transport from the inland hub to a Gulf Coast dock, terminal fees, ocean freight, insurance, and the quality difference between the two crudes. What remains is the incentive.

Worked example with stated inputs

Inputs: EIA weekly spot prices for Brent (FOB) and WTI (Cushing), checked October 22, 2026. Transport costs are illustrative round numbers chosen for the arithmetic, not market quotes: $1.50 per barrel from Cushing to a Gulf Coast dock and $3.00 per barrel for an Atlantic voyage including insurance, $4.50 in total.

Sources: EIA weekly Europe Brent spot price FOB, WTI Cushing spot price, and U.S. exports of crude oil (checked October 22, 2026). Spread and residual computed by PetroEyes; the $4.50 cost is an illustration.

Read the table in two halves. In the first four weeks the spread averaged about $11.60 and exports averaged 4,003 thousand b/d. In the second four weeks the spread averaged about $25.40, more than double, and exports averaged 4,087 thousand b/d, about 2 percent higher. A price incentive that more than doubled produced almost no change in weekly export volume over the same eight weeks.

The data alone cannot say why, but the candidate reasons are structural. Cargoes are arranged weeks before they load, so a spread that opens in September shows up in loadings later. Dock space, tanker availability, and pipeline capacity to the coast cap how fast volumes can respond. And WTI at Cushing is not the price a Gulf Coast exporter actually receives; coastal grades and freight rates move too, and a surge in tanker demand can absorb part of the spread. The general lesson holds beyond this episode: the spread tells you the direction of the incentive, and the physical system decides how much of it turns into barrels and how quickly.

Ships, docks, and channel depth

Physical limits are not abstract. In a May 16, 2018 analysis the EIA explained that all onshore Gulf Coast ports that trade petroleum sit in inland harbors reached through dredged channels or rivers, and that those channels are not deep enough for a fully loaded very large crude carrier (VLCC). A VLCC is designed to carry about 2 million barrels. The docks can load Aframax tankers of about 500,000 barrels or Suezmax tankers of about 900,000 to 1,000,000 barrels; four Aframaxes or two Suezmaxes carry what one VLCC does.

Exporters work around this with partial loadings and reverse lightering, in which smaller vessels shuttle crude out to a VLCC waiting offshore. At the time of that analysis the EIA identified the Louisiana Offshore Oil Port, with deepwater single-point moorings, as the only US facility able to accommodate a fully loaded VLCC. Each extra step adds cost, and the EIA noted that using smaller ships requires a wider spread between US and international crude prices to make the trip pay. That is the link between the dock and the arbitrage table above: shallow channels raise the threshold the spread must clear. Whether newer offshore terminals have changed that picture since 2018 is a question for current port and project data, which this page does not cover.

A scale check helps when reading cargo news. At 3.96 million b/d, a year of US crude exports is roughly 1.45 billion barrels, the equivalent of about 720 fully loaded VLCCs, or nearly two a day. A single cargo is half a day of national exports, which is exactly why the weekly numbers jump around.

Which coast the barrels leave from

The EIA also reports crude exports by the refining district, or PADD, from which they leave the country. That series turns the dock discussion above into numbers, and it shows how completely the export business has become a Gulf Coast business since the ban ended.

Source: EIA, Crude Oil Exports by PADD, annual, thousand barrels per day (checked October 28, 2026). Shares computed by PetroEyes.

In 2016, the first full year after the repeal, the Gulf Coast handled just under half of crude exports, 49.2 percent, and the East Coast 28.9 percent. A year later the Gulf Coast share was 79.6 percent, by 2019 it was 93.3, and in 2025 it was 96.7 percent: 3,829 of the 3,961 thousand barrels a day. The Midwest share fell from 18.6 percent in 2017 to 2.8 percent, and East Coast exports, 171 thousand b/d in 2016, were 15 in 2025. The pattern follows production. Texas and New Mexico, the two states over the Permian Basin, are the two largest producing rows in the production by state guide, and both sit inside PADD 3 itself, as the PADD guide lists, so the district that produces the most crude is also the district where 96.7 percent of exports leave. The PADD series records the district of exit only; it does not say which field a cargo came from.

The concentration has a practical meaning for anyone reading the weekly numbers. Because almost the entire export flow crosses docks in one district, events in that district show up in the national export figure almost one for one. A channel closure, a storm that shuts Gulf ports for several days, or a single terminal outage can move a weekly national export estimate by hundreds of thousands of barrels a day without any change in the economics behind the trade; at roughly 2 million barrels a cargo, one delayed VLCC-sized loading is about 285 thousand b/d over a seven-day week. When a weekly export number collapses, the first check is the Gulf Coast port news for that week, before any theory about demand abroad. The second check is the Gulf Coast crude stock line in the same weekly report: a cargo that did not sail may still be sitting in a coastal tank, in which case it can reappear as an export in a later week.

Weekly, monthly, annual: three versions of the same flow

The EIA publishes crude exports in three forms, each with a different purpose and accuracy.

Sources: EIA Today in Energy, August 31, 2016 (near-real-time export data) and March 10, 2026 (2025 exports, based on the Petroleum Supply Monthly and Annual), checked October 22, 2026.

Why the weekly method changed matters for how much trust to place in it. The EIA said that in the first six months of 2016, before it switched to customs data, its weekly estimates underestimated total crude oil, petroleum, and biofuel exports by an average of 16 percent compared with final monthly data. The customs-based method narrowed that gap, but the weekly figure is still an estimate that the monthly series later replaces.

Worked example: twelve weeks of noise

Inputs: EIA weekly crude export estimates for the twelve weeks ending July 31 through October 16, 2026, in thousand b/d: 3,685; 3,058; 4,066; 3,792; 4,483; 3,417; 4,831; 3,281; 3,570; 4,765; 4,570; 3,442.

• Twelve-week average: 46,960 / 12 = about 3,913 thousand b/d.
• Range: 3,058 (week ending August 7) to 4,831 (week ending September 11), a spread of 1,773 thousand b/d.
• Latest four-week average (September 25 to October 16): 16,347 / 4 = about 4,087 thousand b/d.
• The single latest week, 3,442, is 645 below that four-week average, about 4.5 million barrels over seven days, or a little more than two VLCC cargoes shifting from one week to the next.

A headline that says "crude exports plunge" on the latest week would be describing ordinary cargo timing. The four-week average sits close to the 2025 annual figure. This is the same discipline the Weekly Petroleum Status Report guide recommends for every line in the report: average the noisy flows, and wait for the monthly data before calling a trend.

One more caution about secondary data: some aggregated datasets label total petroleum exports, about 10.15 million b/d in 2023 by the EIA's count, as "crude exports." If a figure for US crude exports is close to or above domestic crude production, check the series definition before using it.

Seven misreadings that export data invite

1. Treating gross exports as net. 4.0 million b/d out does not make the US a net crude exporter; 2.2 million b/d net came in.
2. Treating crude as all petroleum. The net export position exists only when products are included.
3. Calling a week a trend. A one-cargo swing moves a weekly figure by roughly 285,000 b/d.
4. Assuming record output means record exports. 2025 had both a production record and an export decline; stock builds and domestic refining took the difference.
5. Reading the WTI-Brent spread as profit. Pipeline, terminal, freight, and quality differences come out of it first.
6. Assuming destinations are stable. China went from second-largest buyer in 2023 to an 89 percent drop in 2025.
7. Comparing weekly and monthly series directly. They are built from different sources and revise differently.

How exports fit with refining and storage

Every barrel produced in the US has three destinations: a domestic refinery, a storage tank, or an export dock. The 2025 data show the trade-off plainly, with the EIA attributing the export dip to more crude going into storage, particularly the Strategic Petroleum Reserve, and to domestic refineries. Reading exports in isolation therefore misses half the balance. Pair them with refinery inputs and with stock changes, including the Strategic Petroleum Reserve levels, and the export figure becomes the visible residual of decisions made elsewhere in the system. The refining side of that balance, including the 2025 closures that removed about 263,000 b/cd of national capacity, is set out in the US refinery capacity 2026 guide.

What to check when the next numbers arrive

Three releases decide whether the autumn 2026 spread shows up in export volumes. Each Wednesday, the weekly report adds another export estimate; the four-week average is the line to track against the roughly 4.1 million b/d of late September to mid-October. Each month, the Petroleum Supply Monthly replaces the weekly estimates with census-based totals and adds the destination split, which is where a shift toward Europe or Asia would first appear with confidence. And early in 2027 the EIA's annual summary will say whether 2026 recovered from the 2025 dip or extended it.

Between releases, the useful cross-checks are the spread itself, the Cushing stock level that anchors WTI, and domestic refinery runs. If the spread stays wide while refinery inputs fall and Cushing stocks build, more crude is available to leave and the export figure should rise. If refiners keep running hard, as the 2025 data show they can, the domestic system absorbs more of the barrels the spread is trying to pull abroad.

Reader questions on US crude exports

Next step: the export incentive starts with the price gap between two benchmarks. The WTI vs Brent spread explainer shows what normally sets that gap and how to judge whether a move like autumn 2026's is about US supply or about the international market.

Sources (all checked October 22, 2026): EIA Today in Energy, Annual U.S. crude oil exports decrease for first time since 2021 (March 10, 2026); EIA annual crude oil exports; EIA net imports of crude oil; EIA net imports of crude oil and petroleum products; EIA weekly crude oil exports; EIA weekly Brent spot price; EIA weekly WTI spot price; EIA Today in Energy, Gulf Coast port limitations (May 16, 2018); EIA Today in Energy, near-real-time export data (August 31, 2016); Public Law 114-113 (govinfo); EIA FAQ, How much petroleum does the United States import and export (2023 data); Federal Reserve Bank of Kansas City, Flowing Crude (2017). Checked October 28, 2026: EIA crude oil exports by destination, annual; EIA crude oil exports by PADD, annual; EIA crude oil imports by country of origin, annual (Canada, 2025). Ratios, averages, and the worked examples are PetroEyes calculations from those published values.