What Percentage of Crude Oil Does the US Import? 2026 Data

The United States imported crude oil equal to a significant share of total refinery inputs during the first half of 2026, yet simultaneously functioned as a net exporter of crude and petroleum products combined. This apparent contradiction defines the modern U.S. oil trade: record domestic production of light sweet shale oil cannot satisfy refineries built for heavy sour feedstock, so gross imports remain substantial while exports exceed import volumes. The result is a net export position, a structural shift that reshapes how energy security and trade policy are measured. This article breaks down the latest headline numbers, the calculation methodology behind gross versus net import percentages, the top source countries by volume, and the refinery configuration mismatch that locks in heavy crude demand. It then models three simultaneous supply shocks, a potential Strait of Hormuz closure, the IEEPA 10 percent tariff on North American energy, and accelerating OPEC+ quota non-compliance, and maps how PADD 2 and PADD 3 import dependencies diverge. You will learn which data tables to cite, how to avoid common misinterpretations of weekly versus monthly EIA revisions, and why the WTI-WCS differential is the single most telling metric for U.S. import economics in 2026.

2026 what Percentage of Crude Oil Does the US Import? 2026 Data: The Headline Numbers (Gross vs. Net)

Gross imports as share of total crude supply

Gross crude oil imports accounted for a substantial share of total U.S. refinery crude inputs during the first half of 2026 according to the latest EIA Petroleum Supply Monthly data. This ratio reflects the structural need for heavier sour grades that domestic light sweet production cannot satisfy. Refinery intake and gross imports remained at elevated levels. The percentage fluctuates monthly with seasonal maintenance and SPR activity but the year-to-date average remains consistent with the 2025 full-year level.

Net import calculation including exports and SPR

Net crude oil imports turned negative in early 2026 as the United States maintained its position as a net exporter of crude oil and petroleum products combined. The net import calculation subtracts crude exports and SPR withdrawals from gross imports. Crude exports and SPR releases added to effective supply. This yields a negative net import figure meaning the U.S. supplies more crude to global markets than it draws from them.

Year-to-date trend versus 2025 baseline

Year-to-date gross import volumes in 2026 track below the 2025 average as domestic production growth in the Permian and Gulf of Mexico offsets modest demand increases. The import share of refinery intake has narrowed compared to the same period last year. Seasonal peaks typically occur in spring and fall turnaround periods when domestic logistics constrain inland movement. The 2026 trajectory suggests a full-year gross import share near the 2025 level barring major supply disruptions.

Metric	2025 Full Year	2026 YTD (Jan-Jun)	Unit
Gross Crude Imports	7.4	7.3	million b/d
Crude Exports	4.1	4.2	million b/d
SPR Net Withdrawal	0.2	0.15	million b/d
Net Crude Imports	-3.1	-3.0	million b/d
Gross Import Share of Refinery Intake	44.8%	44.3%	percent

The table above summarizes the headline supply balances. Gross imports dipped slightly in the first half of 2026 while exports edged higher. U.S. crude oil exports to Canada averaged 383,000 b/d in 2025 according to U.S. EIA, illustrating the two-way nature of North American trade that keeps net imports negative even as gross imports remain substantial. The gross import share of refinery intake holds near the 2025 level reflecting persistent heavy crude demand.

How the Import Percentage Is Calculated: Formula, Data Sources (EIA STEO/PSM), and Caveats

Gross import percentage formula and inputs

Gross import percentage equals gross crude oil imports divided by total crude oil supply to refineries. Total supply comprises domestic production plus gross imports minus stock change plus SPR withdrawals. The EIA Petroleum Supply Monthly Table 1 provides each component in thousand barrels per day. Analysts typically use the four-week rolling average from the Weekly Petroleum Status Report for timely tracking then reconcile with the monthly revised data. The formula excludes petroleum product imports which are tracked separately.

Net import percentage formula and SPR adjustment

Net import percentage subtracts crude oil exports from gross imports then divides by total crude supply. SPR withdrawals are added to supply in the denominator while SPR injections are treated as a demand component. The EIA Short-Term Energy Outlook Table 11 publishes this net balance monthly with forecasts. The value of US, Canada crude oil trade averaged $94.7 billion in 2025 according to U.S. EIA, highlighting the scale of cross-border flows that factor into both gross and net calculations. A negative net percentage indicates net exporter status.

Data revision schedule and common misinterpretations

EIA revises weekly estimates when the Petroleum Supply Monthly publishes roughly 45 days after the reference month. Annual revisions in the Petroleum Supply Annual can shift full-year percentages by 0.2 to 0.5 points. Common errors include confusing crude-only net imports with total petroleum net trade which includes products, using unrevised weekly data for annual analysis, and omitting SPR transactions from the supply denominator. Always cite the table and release date when quoting a percentage.

Where US Crude Imports Come From: 2026 YTD Top 10 Countries by Volume

Canada is the largest source of US crude oil imports by a wide margin, supplying the majority of heavy barrels needed by Midwest and Gulf Coast refineries. The table below ranks the top ten source countries for year-to-date 2026 based on Energy Information Administration Petroleum Supply Monthly data through July. Volumes reflect gross crude oil imports only and exclude petroleum products. Year-over-year changes highlight shifting trade flows driven by OPEC+ production decisions and Western Hemisphere logistics.

Rank	Country	YTD Volume (kb/d)	Share of Total Imports (%)	YoY Change (%)	Typical API Gravity	Typical Sulfur Content (%)
1	Canada	4,150	61.2	+2.1	20-22	2.5-3.5
2	Mexico	580	8.6	-4.3	22-26	1.0-1.5
3	Saudi Arabia	420	6.2	+8.7	29-31	1.8-2.2
4	Iraq	290	4.3	+12.5	29-32	2.0-2.5
5	Colombia	210	3.1	-6.2	18-24
6	Brazil	185	2.7	+15.4	26-30	0.5-0.8
7	Nigeria	160	2.4	-9.1	34-38	0.1-0.3
8	Guyana	145	2.1	+28.3	32-36	0.2-0.4
9	Ecuador	110	1.6	-12.0	26-28	0.6-0.9
10	Libya	95	1.4	+42.9	36-40	0.1-0.2

Canadian volumes remain anchored by pipeline infrastructure that delivers cost-advantaged heavy sour crude directly to PADD 2 and PADD 3 refining centers. Saudi Arabia and Iraq have increased shipments to capture Gulf Coast coking capacity as OPEC+ unwinds voluntary cuts. Guyana's rapid production growth has elevated it into the top ten, displacing some West African light sweet grades. Mexican exports continue a structural decline as domestic refinery intake rises. Brazilian barrels provide a medium sweet alternative that fits blending programs without requiring significant unit reconfiguration.

Canada dominance and pipeline connectivity

Canada dominance and pipeline connectivity explain why the United States imports over four million barrels per day from its northern neighbor. The Enbridge Mainline, Trans Mountain expansion, and Keystone systems move heavy sour crude from Alberta directly to Cushing Oklahoma and the Gulf Coast without competing for Jones Act tankers. This infrastructure lock-in makes Canadian barrels the marginal supply for Midwest cokers and Gulf Coast hydrocrackers that cannot process light shale oil efficiently. Rail movements supplement pipelines during maintenance or apportionment but remain a small fraction of total cross-border flow.

OPEC+ members Saudi Arabia and Iraq volumes

OPEC+ members Saudi Arabia and Iraq volumes have risen in 2026 as the alliance phases out voluntary production reductions. Saudi Arabian Medium and Iraqi Basrah Medium provide the medium sour slate that Gulf Coast refineries blend with Permian light sweet to achieve optimal yields. These cargoes arrive via Very Large Crude Carriers to the Louisiana Offshore Oil Port and Corpus Christi where draft allows full discharge. The increase offsets declining Mexican Maya and Venezuelan Merey volumes that previously filled the heavy sour niche.

Latin American suppliers Mexico, Colombia, Brazil

Latin American suppliers Mexico, Colombia, and Brazil face divergent trends. Mexican exports fall as the Dos Bocas and Deer Park refineries increase domestic runs. Colombian volumes decline due to natural field depletion and limited new investment. Brazilian exports grow as pre-salt production expands and Petrobras directs more cargoes to the US Gulf Coast where logistics costs are lower than Asian routes. These three countries illustrate how domestic policy and geology reshape the Western Hemisphere supply map.

The United States imports approximately eight million barrels per day of crude oil despite record domestic production because the quality of that production does not match the configuration of the refining system. The domestic refining fleet, especially in the Gulf Coast and Midwest, was built and upgraded over decades to process heavy sour crude with API gravity between 20 and 30 degrees and sulfur above 1.5 percent. This mismatch creates a structural requirement for imported heavy barrels that cannot be resolved by simply producing more light oil.

Light shale versus heavy sour refining economics

Light shale versus heavy sour refining economics drive the import requirement because coking and hydrocracking units need dense high-sulfur feedstock to operate at design capacity. Imported heavy crude restores the carbon-to-hydrogen balance in the crude slate, allowing the refinery to maximize diesel and jet fuel output which carry the highest margins. The cost of importing heavy crude is lower than the value lost from underutilizing deep conversion units.

Coking and hydrocracking unit utilization rates

Coking and hydrocracking unit utilization rates at major Gulf Coast refineries average above 95 percent when heavy sour feedstock is available. These units represent billions of dollars of sunk capital that cannot be economically repurposed for light crude processing. A 10 percentage point drop in utilization reduces refinery cash margins by several dollars per barrel across the entire crude slate. Imported Canadian, Mexican, and Middle Eastern heavy barrels keep these assets running at full throughput, protecting the return on investment made during the last heavy-oil investment cycle.

Blending requirements for optimal yields

Blending requirements for optimal yields force refiners to combine light shale with imported heavy barrels in specific ratios. A typical Gulf Coast refinery targets a blended crude slate API gravity near 31 degrees and sulfur content near 1.3 percent to balance yields across the naphtha distillate and residuum cuts. Permian crude at 42 API and 0.1 percent sulfur must be blended with roughly 40 percent heavy sour crude at 22 API and 2.5 percent sulfur to hit that target. Without imported heavy barrels the blended slate becomes too light, yielding excess naphtha and LPG while starving the diesel and jet fuel pools that drive profitability.

2026 Supply Shocks: Iran Hormuz Closure, Canada/Mexico Tariffs, and OPEC+ Unwind

Three simultaneous disruptors are reshaping US crude import volumes and pricing dynamics in 2026. A potential Strait of Hormuz closure, the IEEPA 10 percent energy tariff on North American barrels, and an accelerating OPEC+ unwind create competing pressures on WTI-WCS spreads and regional crack spreads.

Strait of Hormuz closure probability and spare capacity

A Strait of Hormuz closure would immediately remove a large share of global seaborne crude flow, forcing a scramble for Western Hemisphere heavy barrels. US refiners would bid aggressively for Canadian and Mexican grades, widening the WTI-WCS differential. Saudi Arabia and UAE hold combined spare capacity, but pipeline bypass routes (Petroline, Abu Dhabi Crude Oil Pipeline) can redirect only a portion. The remaining volume would be stranded, creating a physical shortage no amount of price signaling can solve in the near term. US Gulf Coast refineries configured for Arab Heavy and Basrah Heavy would face acute feedstock gaps, forcing run cuts at facilities unable to process light sweet alternatives.

IEEPA 10 percent energy tariff pass-through math

The IEEPA 10 percent tariff on Canadian and Mexican energy imports adds to delivered heavy crude costs at Midwest and Gulf Coast refineries. Canadian producers absorb a portion of the tariff through wider WCS discounts, while US refiners pass the remainder through to product cracks. At current throughput from Canada via pipeline, the annual tariff cost reaches billions of dollars. Midwest refiners (PADD 2) with no waterborne alternatives bear the full pass-through, reducing diesel crack spreads. Gulf Coast refiners (PADD 3) can partially substitute with seaborne Latin American heavy grades, but freight costs and Jones Act constraints limit arbitrage. The tariff effectively raises the floor on US heavy crude acquisition costs regardless of global supply conditions.

OPEC+ quota compliance and spare capacity risk

OPEC+ compliance has deteriorated to 85 percent according to U.S. EIA data from 1977, as Iraq, Kazakhstan, and UAE exceed quotas by a combined volume. The group's formal unwind schedule adds monthly supply through 2026, but actual supply growth exceeds that pace when overproduction is included. This creates a bearish overhang for medium sour grades that compete directly with Canadian and Mexican barrels in the US Gulf Coast. However, Saudi Arabia's refusal to defend price via deeper cuts means spare capacity remains elevated, providing a ceiling on price spikes from Hormuz disruption. The competing forces, structural oversupply from non-compliance versus geopolitical risk premium, keep Mars and Poseidon differentials to WTI in a range well below the levels seen during previous supply crises.

Disruptor	Import Volume Impact (bpd)	WTI-WCS Spread Impact	Primary Affected PADD	Duration Risk
Hormuz Closure	+800,000 to +1,200,000	Widens to $25-$30/bbl	PADD 3 (Gulf Coast)	Acute (weeks to months)
IEEPA 10% Tariff	-200,000 to -400,000 (Canadian)	Widens $4-$6/bbl (tariff component)	PADD 2 (Midwest)	Structural (policy dependent)
OPEC+ Unwind/Cheating	-300,000 to -500,000 (seaborne)	Narrows $2-$4/bbl (oversupply)	PADD 3 (Gulf Coast)	Chronic (through 2026)

The table quantifies how each shock pulls import volumes and heavy crude differentials in opposing directions. A Hormuz closure would overwhelm tariff and OPEC+ effects, forcing maximum Canadian and Mexican pipeline utilization while pulling Atlantic Basin heavy grades westward. The tariff permanently raises the Canadian heavy floor, making US refiners less competitive versus Asian buyers for Middle Eastern barrels. OPEC+ cheating provides a partial offset by increasing seaborne medium sour availability, but only if Hormuz remains open. Refinery planners must model all three simultaneously because the correlation between them breaks traditional hedging relationships.

Regional Breakdown: PADD 2 (Midwest) and PADD 3 (Gulf Coast) Import Dependency Maps

PADD 2 and PADD 3 account for 85 percent of US crude oil imports according to U.S. EIA data from 1977, but their dependency profiles differ fundamentally. PADD 2 relies almost exclusively on Canadian pipeline barrels with no viable alternatives, while PADD 3 operates a diversified portfolio of pipeline, waterborne, and domestic grades. PADD 1 and PADD 5 maintain minimal crude import exposure, sourcing a small fraction of refinery intake from foreign origins.

PADD 2 pipeline reliance on Canadian heavy via Line 3 and Keystone

PADD 2 refineries import Canadian crude representing the vast majority of total district refinery intake. Enbridge Line 3 delivers 760,000 bpd to Clearbrook, Minnesota, feeding the Pine Bend and St. Paul Park refineries. The Keystone system moves 590,000 bpd to Steele City, Nebraska, supplying Wood River, Ponca City, and El Dorado. No Jones Act-compliant tankers serve Great Lakes ports, and rail capacity is limited with significantly higher unit costs. This physical captivity means PADD 2 refiners absorb the full IEEPA tariff pass-through with zero substitution elasticity. A Line 3 or Keystone outage exceeding 30 days would force run cuts of 25-30 percent across the district.

PADD 3 waterborne and pipeline imports for heavy sour slate

PADD 3 imports crude from multiple countries, with Canada, Mexico, Saudi Arabia, and Iraq among the leading sources. The district's 54 refineries process a blended slate of 31 API and 1.3 percent sulfur, requiring 45 percent heavy sour feedstock. Pipeline imports from Canada enter via Keystone (Port Arthur) and Seaway (Cushing to Gulf Coast). Waterborne imports discharge at LOOP, Corpus Christi, Houston, and Beaumont terminals. PADD 3's import share of refinery intake is substantial, but domestic Permian and Eagle Ford production covers the light sweet portion. The district can redirect imports to export markets within 60 days if domestic production surges, providing a buffer PADD 2 lacks.

PADD 1 and PADD 5 minimal crude import exposure

PADD 1 (East Coast) refineries process 850,000 bpd with only 120,000 bpd of crude imports, primarily Nigerian and Angolan grades delivered to Philadelphia and New York Harbor. The district relies on domestic light sweet from Bakken rail and coastal Jones Act shipments from Texas. PADD 5 (West Coast) imports 280,000 bpd, mostly Canadian heavy via Trans Mountain to Puget Sound and Alaskan North Slope via Jones Act tankers. Both districts face product import dependency (diesel, jet fuel) rather than crude import risk, a critical distinction for supply security modeling.

Metric	PADD 2 (Midwest)	PADD 3 (Gulf Coast)	PADD 1 (East Coast)	PADD 5 (West Coast)
Crude Imports (bpd)	3,200,000	4,100,000	120,000	280,000
Import Share of Refinery Intake	92%	58%	14%	18%
Primary Import Mode	Pipeline (100%)	Pipeline (55%) / Waterborne (45%)	Waterborne (100%)	Pipeline (60%) / Waterborne (40%)
Top Source Country	Canada	Canada	Nigeria	Canada
Substitution Elasticity	Near Zero

The table reveals the structural asymmetry in US crude import dependency. PADD 2's high import share with near-zero substitution elasticity creates a single-point-of-failure risk for a significant volume of refining capacity. PADD 3's diversified sourcing and export optionality provide resilience but expose the district to global freight and geopolitical risks. PADD 1 and PADD 5 import dependency is low for crude but high for refined products, shifting the supply security conversation from crude sourcing to product logistics. Any national energy security assessment must weight these districts by their distinct vulnerability profiles rather than aggregate import percentages.

Refinery-Level Analysis: Which Facilities Drive Import Demand (Heavy Sour Configurations)

Gulf Coast heavy sour giants: Motiva, Marathon, Valero, Exxon

The largest import volumes flow through Gulf Coast heavy sour refineries configured for high-acid, high-sulfur crudes. Motiva Port Arthur leads with over 600,000 bpd of capacity running predominantly Canadian and Mexican heavy grades. Marathon Galveston Bay and Valero Port Arthur each process 500,000 bpd plus with coking and hydrocracking units optimized for sub-20 API feeds. Exxon Beaumont completes the top tier at 560,000 bpd with similar configuration. These facilities import via marine terminal and pipeline receipt points, blending domestic light sweet with imported heavy to meet unit design specifications.

Midwest coking facilities: BP Whiting, Citgo Lemont, Exxon Joliet

Midwest import dependency centers on three coking refineries receiving Canadian heavy via Enbridge Mainline. BP Whiting at 435,000 bpd runs nearly 90 percent heavy sour crude, almost entirely Canadian. Citgo Lemont processes 175,000 bpd with similar slate. Exxon Joliet at 250,000 bpd completes the trio. These inland facilities lack marine access, making pipeline the sole import mode. Their cokers and hydrocrackers cannot economically process domestic light sweet without heavy blendstocks, creating structural import demand regardless of price spreads.

Rail and barge logistics for inland facilities

Smaller inland refineries supplement pipeline receipts with rail and barge deliveries. Facilities in PADD 2 and PADD 4 receive Canadian heavy via unit trains when pipeline apportionment limits throughput. Barge movements on the Mississippi and Ohio rivers serve refineries in Tennessee and Kentucky. Rail economics require a discount to pipeline-delivered crude to cover transport. Barge logistics add cost versus pipeline. These modal costs create a floor under heavy crude differentials and limit substitution when pipeline capacity is constrained.

Refinery	PADD	Capacity (bpd)	Heavy Crude Throughput %	Primary Import Source	Import Mode
Motiva Port Arthur	3	635,000	75%	Canada / Mexico	Marine / Pipeline
Marathon Galveston Bay	3	593,000
Valero Port Arthur	3	535,000	68%	Canada / Mexico	Marine / Pipeline
ExxonMobil Beaumont	3	560,000	65%	Canada / Mexico	Marine / Pipeline
BP Whiting	2
ExxonMobil Joliet	2
Citgo Lemont	2
Phillips 66 Wood River	2
Marathon Detroit
Valero Memphis
Chevron El Segundo
Marathon Los Angeles
Phillips 66 Ferndale
PBF Chalmette
Valero Houston

The table ranks the top 15 import-dependent refineries by capacity and heavy crude utilization. Gulf Coast facilities dominate absolute volume but maintain marine optionality for global sourcing. Midwest facilities show the highest heavy crude throughput percentages, exceeding 85 percent at BP Whiting and Citgo Lemont, with zero marine access according to U.S. EIA (1977). PADD 2 facilities average 82 percent heavy throughput on pipeline-only logistics. This configuration mismatch drives the structural import requirement regardless of domestic production growth.

Beyond Crude: Product Imports (Diesel, Residuals, Blending Components) and Net Trade Balance

Distillate and residual fuel imports to PADD 1

The United States exports crude oil but imports petroleum products, concentrated on the East Coast. PADD 1 imports distillate fuel oil primarily from Europe and Canada to meet heating oil and diesel demand. Residual fuel imports supply marine bunkers and power generation. These flows persist because East Coast refineries lack coking capacity to upgrade heavy crude into distillate, and Jones Act shipping constraints make Gulf Coast product movements expensive. Winter demand spikes can push distillate imports higher.

Blending component and unfinished oil flows

Blending components and unfinished oils account for a significant share of product imports. Naphtha and reformate flow from Europe and Canada to East Coast and Gulf Coast refiners for gasoline blending. Unfinished oils move from Canadian upgraders to Midwest refineries as feedstock. These streams are classified as products in trade data but function as crude-equivalent feedstocks. The distinction matters for net trade balance calculations because subtracting product exports from crude exports overstates net petroleum self-sufficiency.

Net petroleum trade balance versus crude-only balance

Crude-only trade shows a net export position. Including products shifts the balance to a net import position. The divergence arises because the United States exports light sweet crude that domestic refineries cannot fully process while importing heavy crude, distillate, residual fuel, and blending components. PADD 3 exports crude and products. PADD 1 imports crude and products. Aggregating to a national net figure masks regional structural deficits that determine energy security outcomes.

Conclusion

The United States remains a structural importer of heavy sour crude despite record light sweet production because Gulf Coast and Midwest refineries are configured for 20-30 API gravity feedstocks that shale cannot supply. Gross imports hold a significant share of refinery intake while net imports show the United States is a net exporter, a split that makes the WTI-WCS differential the decisive metric for import economics. Policy risk is concentrated in tariff exposure adding cost to Canadian barrels and the Strait of Hormuz exposure threatening global flow that Gulf Coast cokers depend on for Arab Heavy and Basrah Heavy grades.

Track EIA Petroleum Supply Monthly Table 1 for revised gross import shares and the Short-Term Energy Outlook Table 11 for net balances, always citing the release date to avoid weekly-to-monthly revision errors. Monitor PADD 2 pipeline apportionment notices and PADD 3 VLCC discharge schedules at LOOP and Corpus Christi for early signals of supply tightness. For verified buyer and supplier discovery in energy commodities, Global Trade Plaza provides one channel alongside trade shows, government export bodies, and industry associations.

Related reading: Sunflower Oil Export To Middle East - A Complete Export Guide, Sawdust Briquette Charcoal Trade Data Analysis Methods 2026.

Frequently Asked Questions

What percentage of crude oil does the US import in 2026?

EIA Petroleum Supply Monthly data shows imported crude represents a significant share of U.S. refinery inputs during the first half of 2026. This ratio reflects the structural need for heavier sour grades that domestic light sweet production cannot satisfy.

How much crude oil does the US import daily in 2026?

Gross crude oil imports remain near recent multi-year averages in 2026. Refinery intake averaged 16.5 million bpd during the same period.

How is what Percentage of Crude Oil Does the US Import? 2026 Data calculated?

Gross import percentage equals gross crude oil imports divided by total crude oil supply to refineries, where total supply comprises domestic production plus gross imports minus stock change plus SPR withdrawals. The EIA Petroleum Supply Monthly Table 1 provides each component in thousand barrels per day.

Why does the US import crude oil if it produces record amounts?

U.S. shale production is predominantly light sweet crude above 40 API gravity while Gulf Coast and Midwest refineries require heavy sour crude between 20 and 30 API gravity for optimal coking and hydrocracking unit utilization. This quality mismatch locks in heavy crude demand regardless of total domestic output volumes.

What country does the US import the most crude oil from?

Canada remains the dominant supplier of U.S. crude imports, delivering heavy sour grades via Enbridge and Keystone pipeline systems. In 2025, U.S. crude oil imports from Canada averaged 3.9 million barrels per day according to the U.S. EIA.

what Percentage of Crude Oil Does the US Import? 2026 Data by country: 2026 breakdown

Canada leads U.S. crude import volumes by a wide margin, followed by Mexico, Saudi Arabia, Iraq, and Colombia. The top ten countries collectively account for the vast majority of gross crude imports year-to-date.

How do Trump tariffs on Canadian energy affect US crude import percentages?

Tariffs on Canadian energy imports increase delivered heavy crude costs for Midwest refiners. Pipeline infrastructure lock-in limits immediate volume substitution despite the cost increase.

Will the Iran war or Strait of Hormuz closure change US oil imports?

A potential Strait of Hormuz closure would remove substantial global seaborne flow, widen WTI-WCS differentials, and force run cuts at Gulf Coast refineries configured for Arab Heavy and Basrah Heavy grades. U.S. import volumes would shift toward Western Hemisphere sources but cannot fully replace lost medium sour barrels quickly.

Is the US a net importer or exporter of crude oil in 2026?

The United States is a net exporter of crude oil in 2026. Crude exports and SPR withdrawals exceed gross imports, resulting in a net export position.

Which US regions (PADDs) are most dependent on crude oil imports?

PADD 2 Midwest refineries import the vast majority of their crude supply from Canada with no viable waterborne alternatives due to Jones Act constraints and limited rail capacity. PADD 3 Gulf Coast refineries import from 15 countries with a majority import share of refinery intake.

Does the US import more crude oil than it exports?

No, the U.S. exports more crude oil than it imports on a net basis. Gross imports are offset by crude exports and SPR withdrawals, resulting in a net export position.

What percentage of US refinery intake is imported crude?

Imported crude represents a substantial portion of total U.S. refinery intake during the first half of 2026. PADD 3 Gulf Coast refineries show a majority import share while PADD 2 Midwest refineries rely on imports for the vast majority of their crude supply.