U.S. Oil Infrastructure Map: State Production, Upstream Basins, Refineries, Pipelines, Terminals & Storage with Live EIA Data

The United States produces approximately 13.6 million barrels of crude oil per day — the largest national crude output in history — across 31 producing states, 13 major upstream basins, and the federal Gulf of Mexico. This output feeds roughly 18.0 million barrels per calendar day of refining capacity across 97 facilities in our database, connected by 48 crude oil pipeline systems to a Gulf Coast export complex that shipped approximately 4.1 million barrels per day in 2025. Underpinning the system is about 1.37 billion barrels of crude oil storage, split between 714 million barrels across four Strategic Petroleum Reserve salt-cavern sites and roughly 653 million barrels of commercial working storage at hubs, terminals, and refineries. For commercial real estate professionals evaluating gas stations, truck stops, convenience stores, and industrial properties, this infrastructure network defines the economic geography of fuel supply, site viability, and energy-corridor development.

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This interactive map is the production workhorse behind MMCG Invest's gas station feasibility studies, truck stop feasibility studies, and convenience store feasibility studies. It plots a state-level production choropleth for all 31 producing states, 13 upstream basins with operator breakdowns and breakevens, 97 refineries (32 at 200K+ b/cd and 65 smaller, with flags for closed and closing facilities), 48 pipeline systems color-coded by 13 corridor categories, 35 export and import terminals, and 16 strategic storage facilities including all four SPR sites. Pipeline flows animate proportionally to throughput, with line weight and speed reflecting utilization from sub-30 percent on legacy lines to near-100 percent on Gray Oak and Cactus II. Dynamic tank-fill markers for Cushing, the SPR aggregate, and total U.S. commercial stocks update weekly from the EIA Weekly Petroleum Status Report, with 26-week sparkline charts in each popup. A live ticker surfaces weekly crude stocks, Cushing and SPR levels, refinery utilization, production, exports, and imports with week-over-week deltas. Three basemap modes (Light, Satellite, Streets) toggle between analytical clarity and geographic context.

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State Production Geography: The 31-State Producing Footprint

This release is the first to incorporate a full state-level production choropleth covering all 31 producing states, with 2025 annual-average data sourced from the EIA Petroleum Supply Monthly (released March 6, 2026). The geographic concentration is extreme and commercially consequential.

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Texas alone produces approximately 5.75 million barrels per day — 42.3 percent of total U.S. crude output — driven by Permian (Midland + Delaware sub-basins) and Eagle Ford activity. New Mexico, effectively the Delaware Basin's northern half, contributes another 2.24 million barrels per day for 16.5 percent of national supply. Texas and New Mexico together produce 58.8 percent of U.S. crude, a concentration with no analogue in any other major oil-producing country and which drives the entire Gulf Coast midstream buildout.

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Beyond the Texas–New Mexico duo, the top ten producing states include North Dakota (1.15 million b/d, Bakken/Three Forks), Colorado (467,000 b/d, DJ Basin/Niobrara), Alaska (421,000 b/d, predominantly North Slope), Oklahoma (405,000 b/d, SCOOP/STACK and legacy Anadarko), Wyoming (290,000 b/d, Powder River), California (257,000 b/d, San Joaquin Valley), Utah (185,000 b/d, Uinta), and Ohio (139,000 b/d, Utica Shale). Federal offshore production in the Gulf of Mexico adds approximately 1.9 million barrels per day that is excluded from state totals but appears on the map as a separate BOEM-administered layer.

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Year-over-year trends embedded in each state popup reveal structural dynamics that matter for long-duration lending. Texas grew 1.4 percent in 2025 and 20.2 percent over five years — organic Permian growth moderating but still positive. North Dakota contracted 3.3 percent on Bakken maturity and takeaway constraints. Colorado and Oklahoma show similar aging-basin dynamics. California's 5-year decline of approximately 29 percent reflects regulatory-driven upstream decommissioning and sits alongside the sharpest refinery-closure wave in the country. These trends directly inform the 5-to-10-year demand outlook that SBA feasibility studies and USDA feasibility studies must document.

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Upstream Basins: 13 Plays Driving the National Balance

The map's 13 basin polygons cover every commercially significant U.S. upstream play, each with investment-grade data: oil and gas production, active rig count, breakeven pricing, top-three operators, proved reserves, and technically recoverable resources.

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The Permian Basin remains the dominant structural force in U.S. oil. At approximately 6.6 million barrels per day of crude and 27.0 Bcf/d of associated natural gas, running 242 active rigs against a $35–40/bbl half-cycle breakeven, the Permian produces more oil than most OPEC members individually. ExxonMobil, Chevron, and ConocoPhillips dominate, with an estimated 43 billion barrels of proved reserves. Every midstream investment thesis — pipeline, terminal, refinery, storage — starts with the Permian's production trajectory.

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The Bakken (1.25 million b/d, 28 rigs, ~$48/bbl breakeven, Continental/Hess/Marathon) and Eagle Ford (1.05 million b/d, 43 rigs, ~$40/bbl breakeven, EOG/ConocoPhillips/Chesapeake) are the second-tier oil plays. The DJ Basin/Niobrara (460,000 b/d), Anadarko SCOOP-STACK (375,000 b/d), and Powder River (100,000 b/d) round out the liquids-focused basins.

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On the gas side, the map highlights Marcellus (29.0 Bcf/d), Haynesville (16.5 Bcf/d), Utica/Point Pleasant (7.5 Bcf/d), and the broader Appalachia fairway (36.5 Bcf/d combined) — critical for gas-fired power generation, LNG export feedstock at Sabine Pass and Plaquemines, and petrochemical cracker economics. The Haynesville has become the swing supplier for Gulf Coast LNG, and its breakeven near $3.50/MMBtu Henry Hub makes it exceptionally sensitive to European gas prices.

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The Gulf of Mexico federal OCS carries distinct regulatory and operational risk. BOEM's lease-sale cadence, platform-specific production profiles, and hurricane exposure make GoM basins qualitatively different from onshore plays. Current GoM production of approximately 1.9 million b/d is anchored by Shell's Stones, Chevron's Anchor (the world's first 20,000-PSI operation), and BP's Thunder Horse, with the deepwater renaissance expected to extend long-lived, high-margin barrels into the 2040s.

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Refining Capacity: Consolidation, Closures, and Gulf Coast Gravity

Our map captures 97 refineries — the 32 facilities at 200,000 b/cd or larger that define the bulk of national capacity and 65 smaller specialty, topping, and regional refiners that serve critical local markets. Total operable capacity is approximately 18.0 million barrels per calendar day, consistent with EIA's January 2025 Refinery Capacity Report. The count has declined from a peak of 254 facilities in 1982, driven by consolidation, efficiency gains, and accelerating closures tied to energy-transition economics. The industry lost more than 1.3 million barrels per day of capacity between 2019 and 2023 alone.

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The five largest U.S. refineries — all along the Texas–Louisiana Gulf Coast — are Motiva Port Arthur (641,000 b/cd, Saudi Aramco–owned), Marathon Galveston Bay (631,000 b/cd), ExxonMobil Beaumont (612,000 b/cd after a $2 billion expansion completed in March 2023), Marathon Garyville (606,000 b/cd), and ExxonMobil Baytown (564,000 b/cd). PADD 3 accounts for more than 50 percent of total U.S. refining capacity.

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Recent closures are reshaping regional fuel supply dynamics, and the map flags each with distinct status markers. LyondellBasell permanently closed its 264,000 b/cd Houston refinery in March 2025. Phillips 66 shut its 139,000 b/cd Wilmington, California facility in late 2025. Valero's 145,000 b/cd Benicia, California refinery is scheduled to close in April 2026 with a $1.1 billion impairment charge. California has lost approximately 75 percent of its in-state crude processing capacity over the past two decades, leaving only five operating refineries to serve the state's CARBOB gasoline market — a structural deficit increasingly met by waterborne imports through Los Angeles and San Francisco Bay terminals.

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For CRE professionals, refinery closures create two distinct categories of opportunity: brownfield redevelopment sites of 200 to 1,300 industrially-zoned acres with deepwater, pipeline, or heavy rail access, and a reconfiguration of regional fuel logistics that increases the strategic value of distribution terminals, truck stops, and convenience stores serving the recalibrated supply chain. [INTERNAL LINK: MMCG's gas station and truck stop feasibility studies] routinely incorporate refinery-closure adjacency analysis when a proposed site sits within 150 miles of a closed or closing facility.

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Pipeline Infrastructure: 48 Systems Across 13 Corridor Categories

The map organizes the U.S. crude oil pipeline network into 13 color-coded corridor categories: Permian-to-Corpus Christi, Permian-to-Houston, Permian-to-Nederland, Permian-to-Cushing, Bakken outbound, Keystone, Mid-Continent, refined products, Enbridge/Canadian imports, Rocky Mountain/DJ Basin, Gulf Coast connectors, California/San Joaquin Valley, and Express. Across these categories, 48 pipeline systems are plotted with capacity, length, diameter, year in service, operator, and estimated utilization.

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The Permian Basin drives the largest single-basin pipeline buildout in U.S. history, with takeaway capacity exceeding 6 million barrels per day. The Wink-to-Webster system (ExxonMobil/Plains/MPLX/Delek) is the largest at 1.5 million b/d nameplate, 36-inch diameter over approximately 650 miles; actual throughput runs around 1.35 million b/d. Enterprise's Midland-to-Echo carries 1.07 million b/d across three phases. Gray Oak (980,000 b/d, Enbridge 68.5 percent following the February 2026 equity consolidation), Cactus II (670,000 b/d, Plains 70 percent/Enbridge 30 percent), and EPIC Crude (600,000 b/d, Plains 100 percent since 2025) feed the Corpus Christi export cluster at near-full 85 to 99 percent utilization.

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The Bakken relies primarily on the Dakota Access Pipeline (750,000 b/d, Energy Transfer) to move crude to Patoka, Illinois, with ETCOP extending flows toward Nederland, Texas. DAPL remains operationally secure following the Army Corps' December 2025 Environmental Impact Statement supporting continued operations.

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The Enbridge system is the largest crude oil pipeline network in North America, delivering approximately 3.1 million barrels per day of Canadian heavy crude into the U.S. Midwest through the Mainline/Lakehead system. Enbridge's $1.4 billion Mainline One expansion, approved November 2025, will add capacity for 2027 service. Delivery points at Superior, Wisconsin; Flanagan, Illinois; and Cushing, Oklahoma anchor regional refining clusters that support workforce housing, trucking, and support services — elements MMCG models in hotel feasibility studies and industrial feasibility studies.

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Cushing, Oklahoma functions as the single most important crude oil pricing and storage hub in the United States. As the delivery point for ICE WTI Crude Futures, Cushing's approximately 90 million barrels of shell capacity (about 76 million barrels working) and its connectivity to every major producing basin make it the nexus of U.S. midstream activity. The live tank-fill marker tracks Cushing's weekly inventory and utilization percentage in real time — commercial property values in the Cushing corridor, from truck stops on I-44 to industrial land in Payne and Lincoln counties, correlate directly to these volumes. The Keystone system (TC Energy), Capline (reversed), Seaway (Enterprise/Enbridge), and the Colonial refined-products network round out the nationally significant long-haul corridors.

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Export Terminals: The Gulf Coast VLCC Complex

The United States has undergone a structural transformation from net crude oil importer to the world's largest crude exporter, shipping approximately 4.1 million barrels per day in 2025. This shift, enabled by the 2015 lifting of the crude export ban, has driven a concentrated infrastructure buildout along the Texas Gulf Coast. The map plots 35 terminals across three functional categories: Export, Import, and Both.

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The Enbridge Ingleside Energy Center near Corpus Christi is the largest U.S. crude oil export terminal, handling roughly 25 percent of Gulf Coast crude exports with capacity exceeding 1.6 million barrels per day and 17.6 million barrels of storage, expanding to 20.5 million barrels in its Phase VII buildout. The South Texas Gateway Terminal, also at Ingleside, adds another 800,000 b/d connected to Gray Oak, Cactus II, and EPIC pipelines. In Houston, Enterprise Products' EHT terminal leads at 2.184 million b/d nameplate across 19 ship docks; the ECHO Terminal (Enterprise), ONEOK East Houston (formerly Magellan, acquired for $18.8 billion), and Energy Transfer's HFOTCO collectively provide more than 40 million barrels of storage connecting Permian takeaway pipelines to waterborne export.

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The LOOP (Louisiana Offshore Oil Port), 18 nautical miles off Port Fourchon, is the only U.S. facility capable of fully loading VLCCs at 700,000 deadweight tons. Its 72-plus million barrels of salt-cavern storage and three single-point mooring buoys handle both import and export operations.

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Two proposed deepwater export terminals — Enterprise's SPOT (2 million b/d) and Sentinel Midstream's Texas GulfLink (1.5 million b/d) — have received MARAD licenses but neither has reached final investment decision. Both are flagged "Proposed — No FID" on the map. If built, they would enable full VLCC loading without lightering, potentially reducing export costs by $1 to $2 per barrel.

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Storage Infrastructure: 16 Facilities Across Four Categories

The 16 storage facilities in our database span four functional categories: the four Strategic Petroleum Reserve sites (714 million barrels combined), four major commercial hubs (Cushing, Patoka, Flanagan, Midland), four large commercial terminal complexes, and four third-party operators.

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The four SPR salt-cavern sites are Bryan Mound, Texas (254 MMbbl — the largest), Big Hill, Texas (170 MMbbl), West Hackberry, Louisiana (220 MMbbl), and Bayou Choctaw, Louisiana (75 MMbbl). All four are coastal and marine-loadable, giving the reserve delivery flexibility during supply emergencies. Current SPR inventory runs around 400 million barrels following the 2022 emergency drawdown, and Congress has authorized a gradual refill program that appears on the live ticker as a weekly delta. Commercial storage at Cushing, Patoka Hub, and the Midland/Permian tank farms provides the price-signaling backbone of the WTI futures market.

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Why Oil Infrastructure Mapping Matters for CRE Feasibility

For CRE professionals evaluating gas stations, truck stops, convenience stores, and industrial properties, understanding the upstream and midstream network provides context that generic market data cannot.

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Gas station feasibility studies and convenience store feasibility studies require an understanding of regional fuel supply dynamics. A site supplied by a single refinery faces different risk exposure than one served by a pipeline hub connected to multiple basins. Refinery closures temporarily spike wholesale fuel costs — the California post-Wilmington dynamic is the textbook example — while new pipeline or terminal capacity lowers basis differentials for retailers in connected corridors.

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Truck stop feasibility studies along major freight corridors benefit from pipeline and terminal mapping because crude movement drives ancillary trucking demand. Pipeline construction, refinery turnarounds, and terminal expansions generate temporary workforce surges that lift demand for lodging, food service, and fuel — documented repeatedly in our practice as feasibility study consultant. 

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[INTERNAL LINK: Industrial property feasibility studies] near pipeline hubs follow infrastructure investment cycles. When new pipeline capacity enters service, demand for fabrication yards, pipe coating, compression stations, and logistics staging rises in the surrounding market. The Corpus Christi and Houston Ship Channel corridors have seen sustained absorption driven by export-terminal expansion since 2019.

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For SBA 7(a) feasibility studies and SBA 504 feasibility studies, and USDA B&I feasibility studies, energy infrastructure context strengthens feasibility-study narratives. Demonstrating that a proposed site sits within a well-connected fuel supply network — or that a market faces structural supply constraints due to refinery closures — provides the demand-side analysis that lenders and guarantee programs require. When a subject property sits in one of the 31 producing states, within 100 miles of an active basin, or along a pipeline corridor with measurable utilization trends, that context should appear in the market analysis section of the feasibility report. MMCG's proprietary infrastructure map makes it a two-click process to document.

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Explore the interactive map above to isolate the specific geographic cluster relevant to your site. For deeper analytical work on a specific property or market, MMCG Invest delivers bankable feasibility studies at a fraction of the turnaround time and cost of legacy advisory firms.