The Oil & Gas Value Chain: World Oil & Gas Basins (2026)

Data as of 17 September 2026. How basins are classified — resource class, reservoir, hydrocarbon window, crude quality, extraction method and fiscal regime — is evergreen and is this guide’s spine. Production, reserves, assay and cost figures are dated benchmarks (mostly 2025, sourced beneath each table) to re-source before use; Middle East rows are 2025 baselines that predate the 2026 Hormuz disruption (Section 6.3). The guide is refreshed annually, after the mid-year OPEC and Energy Institute statistical releases. Section 10’s two producers are hypothetical illustrations. This report is for information only and was prepared with AI assistance — see the disclaimer at the end.

Every exploration-and-production (E&P) company you can buy is, underneath the ticker, a portfolio of acreage in oil and gas basins — and the basin decides almost everything that matters: whether the barrels come out as light sweet crude, sour medium crude, tar-like bitumen or dry gas, how they are extracted, what they cost, how fast they decline and who else takes a share of the revenue. That is why an annual report carves a producer into basins, and why a serious energy investor learns to read a company the way a geologist reads a map. This guide is that map for the whole world: North America in depth, then South America, Europe and the Caspian, the Middle East, Africa and Asia Pacific, each basin described with the same set of deposit parameters. For the company-level data behind every basin — each producer screened by production, reserves, netback and cost — go to Metal Pilot’s upstream oil & gas stock screener.

The headline: the world’s oil sits in a few dozen basins that could not be more different — a Saudi carbonate that flows on its own pressure for a few dollars a barrel, a Texas shale that must be fractured well by well, a Venezuelan extra-heavy crude that has to be diluted before it moves, and a Brazilian carbonate under two kilometres of salt and two kilometres of water all feed the same global price.

The Oil & Gas Value Chain series. Part 1: Upstream · Part 2: Midstream · Part 3: Downstream · Part 4: Oilfield Services · Companion: World Oil & Gas Basins · Supplement: Oil Sands

TL;DR & Key Takeaways

• The basin is the unit. A barrel’s value, cost and decline come from its basin’s resource class, reservoir, hydrocarbon window, crude quality and extraction method — so filings report acreage by basin.
• Oil concentrates in a handful of super-basins. The Middle East holds about 55% of the world’s proved crude reserves (OPEC, end-2025); the Permian alone pumps 6.6 MMbbl/d, 48% of US crude; West Siberia, Alberta’s oil sands and Brazil’s pre-salt complete the top tier.
• Crude quality is geology, and it is permanent. Basin crudes run from Bakken’s 44° API, 0.08% sulphur light sweet to Western Canadian Select’s 21°, 3.7% heavy sour and Venezuela’s diluted 16° Merey — a gap no efficiency programme can close.
• The extraction method sets the cost architecture — on a stated basis. Gulf supergiant fields lift existing barrels for about $3.5/boe (Aramco, 2025) and pre-salt floating production vessels (FPSOs) for about $4/boe excluding leases (about $7 with them); a new US shale well needs $65–67/bbl WTI to break even; thermal and extra-heavy projects need the most up-front capital. Never rank running costs and breakevens together.
• Growth and decline sit in different places. Guyana passed 900 kbbl/d six years after first oil, Brazil set a 3.77 MMbbl/d record and Vaca Muerta is the only shale-oil play at scale outside North America; the UK North Sea, Cantarell, Daqing and Burgan manage decline.
• Above ground often decides more than rock. State ownership, the fiscal regime, sanctions (Russia, Iran, Venezuela), security (Libya, Nigeria) and chokepoints such as Hormuz can outweigh geology.

New to upstream? Read straight through from Section 1. Here for one region? Jump to Sections 3–8 — each opens with a deposit-characteristics table and a production-and-economics table. Want the investor’s angle? Sections 9 and 10. Every term is defined in the Vocabulary (Section 12).

1. Why the basin is the unit that matters

A barrel of oil is not a barrel of oil. Bakken crude is a light, sweet stream that refines into fuel with little work and prices near WTI (West Texas Intermediate, the US light sweet benchmark); Alberta bitumen must be diluted just to flow through a pipe and sells at a steep discount; a barrel from Ghawar costs a few dollars to keep flowing, while a new Permian well needs oil in the mid-$60s just to pay for itself — two different cost measures (Section 2), but a gap no operator can close. None of that comes from the company. It comes from the basin — the bowl of sedimentary rock where organic matter was buried, cooked and trapped over tens of millions of years.

Three basin traits do most of the work. The hydrocarbon window — how deep and hot the source rock got — decides whether it made oil, condensate or dry gas; the heaviest crudes are usually oil that later migrated to a shallow, cool margin where bacteria ate its light molecules (Section 4.1). The reservoir and resource class decide whether the hydrocarbons flow to an ordinary well (conventional) or must be fractured, heated, diluted or mined out (unconventional). And maturity and access — pipelines, fiscal terms, politics — decide how much of the barrel’s value reaches the producer.

The resulting map is concentrated: a handful of provinces — the Middle East’s Arabian Basin and Zagros fold belt, the Permian, West Siberia, the Alberta oil sands and Brazil’s pre-salt — carry a disproportionate share of output and reserves, which is why a disruption in one basin can move the global price.

Figure 1. World oil & gas basins at a glance

Figure data: Permian per U.S. EIA, March 2026; Middle East reserve share and Venezuela’s reserves per the OPEC Annual Statistical Bulletin 2026 (end-2025, crude only — OPEC excludes Canada’s oil sands); Brazil per the ANP December 2025 production bulletin (3.770 MMbbl/d; pre-salt 79.63% of output in oil equivalent); Guyana per ExxonMobil, November 2025; Vaca Muerta per Argentina’s Secretaría de Energía data as compiled by Río Negro (approximate); Aramco per its 2025 results; Norway per the Norwegian Offshore Directorate, with “the highest level of production since 2009” per its The Shelf in 2025. A lifting cost is not a breakeven — Section 9 explains the difference.

2. How to read a basin

A filing slices basins four ways: onshore vs. offshore (a shale well drilled in weeks against a deepwater project that commits billions years before first oil); conventional vs. unconventional, as defined in Part 1: Upstream, “Conventional vs unconventional”; the hydrocarbon window, which decides whether a producer is really exposed to oil or natural gas; and the reserves category (proved, probable, possible), which only compares like with like on the same basis.

This guide adds the parameters that make one basin different from another (Table 1). They are the columns of every regional table: the first half describes the deposit, the second how it is produced, on what terms and at what cost.

Table 1. The deposit parameters used in every basin table

Source: resource classes, API and sulphur bands, recovery methods, offshore systems and fiscal regimes as defined in The Oil & Gas Value Chain, Part 1: Upstream, “The product slate & crude quality”, “Conventional vs unconventional”, “Offshore production systems” and “Fiscal regimes”; decline categories per the IEA, which puts average post-peak decline at 2.7% a year for supergiant conventional oil fields, 4.2% for onshore fields and 10.3% for deep offshore fields, and finds tight oil and shale gas output would fall more than 35% within 12 months without new investment. The bands are industry conventions, not standards.

The last row matters most for the regional tables, whose cost column mixes bases: a lifting cost keeps existing wells flowing; an all-in cost adds depreciation, non-income taxes and overheads; a half-cycle breakeven is the oil price that keeps existing wells or plants running, counting diluent, transport and quality discounts where they apply; a full-cycle breakeven adds the capital of a new well or project. Only like ranks with like.

Crude quality is the parameter investors most often skip, and the one that never changes. Figure 2 plots eleven basin crudes on the two quality axes. The shaded corner is light sweet — above 30° API, below 0.5% sulphur — where Bakken and Brent, the North Sea benchmark, sit; moving right costs a refiner sulphur removal, moving down costs coking and diluent, and the heavy sour corner of WCS, Maya and Merey is bid for only by deep-conversion refineries. Indonesia’s Duri shows the axes are independent: heavy does not have to mean sour.

Figure 2. Crude quality of benchmark basin crudes — API gravity vs sulphur

Figure data: Bakken per the ExxonMobil crude assays; Brent, Johan Sverdrup and Urals per the S&P Global Platts EMEA crude specifications, August 2026; Murban per U.S. EIA (Platts data), July 2026; Arab Light per S&P Global; Basrah Medium per Iraq’s SOMO specification as reported by S&P Global, 2020; Duri per the S&P Global Platts Asia Pacific crude specifications, August 2026; Western Canadian Select five-year average per CrudeMonitor; Maya and Merey 16 per the S&P Global Platts Americas crude specifications, July 2026. Shaded zone: light sweet, above 30° API and below 0.5% sulphur. Values are blend specifications or assay averages; cargoes vary.

Units used throughout. Oil and liquids in MMbbl/d (million barrels per day) or kbbl/d (thousand); natural gas flow in Bcf/d (billion cubic feet per day) and gas reserves in Tcf (trillion cubic feet); liquefied natural gas capacity in Mtpa (million tonnes per annum); combined output in boe/d (barrels of oil equivalent, gas at 6 Mcf — thousand cubic feet — ≈ 1 bbl); gas prices in $/MMBtu (per million British thermal units, roughly a thousand cubic feet); and NGLs are natural gas liquids — ethane, propane and butane separated from wet gas. Chinese and some Russian sources report in tonnes, converted here at ~7.3 barrels per tonne, and gas reported in cubic metres is converted at 35.3 cubic feet per cubic metre. Production is a flow; reserves are a stock. All dollar figures are US dollars unless written C$ or A$, and £ is pounds sterling.

Sections 3–8 apply Table 1 region by region: each opens with a deposit-characteristics table and a production-and-economics table, then notes on the basins that matter most.

3. North America

North America — the United States, Canada and Mexico — is where the shale revolution happened and has the widest spread of deposit types in one market: stacked shale, tight siltstone, the world’s largest bitumen accumulation, the deepwater salt basins of the Gulf of America (the Gulf of Mexico in non-US usage) and ageing shallow-water carbonate giants. Everywhere except Mexico sits under concession terms, so North American reserves are barrels the producer owns.

Table 2. North American onshore basins — deposit characteristics

Source: reservoir ages and depths per the formation profiles compiled from the USGS, Alberta Energy Regulator and state geological surveys; crude qualities per the ExxonMobil crude assays (Bakken, Alaska North Slope), CrudeMonitor five-year averages (WCS, Synthetic Sweet Blend, Lloydminster Blend, Edmonton condensate) and the CME Group WTI delivery specification; Eagle Ford, Anadarko and DJ gravity bands per the oil market guide, “Where oil is extracted”; extraction methods per U.S. EIA and operator disclosures. Gravity bands for shale plays are typical ranges, not assays — each play spans several windows.

Every US shale play in Table 2 yields light, sweet oil or condensate from the same horizontal-well-and-fracturing factory, so the continent’s heavy sour barrels come only from Canada’s bitumen and heavy oil and Mexico’s offshore carbonates — and its cost debate is about drilling efficiency, not reservoir engineering.

Table 3. North American onshore basins — production, reserves, operators and cost

Source: US production per the U.S. EIA Short-Term Energy Outlook, September 2026, regional Tables 4a, 5a and 10b (2025 averages; DJ and Gulf Coast rows are the Niobrara–Codell and Austin Chalk formation series, and Barnett and Fayetteville gas the Table 10b formation series); Uinta is Utah’s statewide crude output (186 kbbl/d) and Powder River is derived from Wyoming’s 289 kbbl/d, both per U.S. EIA, 2025, with the basin’s more-than-70% share of Wyoming oil in 2022–24 per the Wyoming State Geological Survey; San Juan processed (“residue”) gas per East Daley, July 2025; Anadarko horizontal-well output per Novi Labs, November 2025, a lower bound that excludes vertical wells; Canadian production per CAPP, 2025; US gas reserves per U.S. EIA, year-end 2024; oil sands reserves per the Government of Alberta citing the AER; Montney, Duvernay and Clearwater per the AER reserves reassessment, 2025, which covers Alberta only (the Montney’s British Columbia portion is excluded); new-well (full-cycle) breakevens per the Dallas Fed Energy Survey, March 2025 ($65 Permian average, $61–70 range across regions) and March 2026 ($67 Permian); oil sands half-cycle cost per S&P Global Commodity Insights, June 2025 ($18–45, average ~$27, WTI basis), and greenfield SAGD per Enverus as cited in Part 1: Upstream, “The cost curve & breakevens”; gas breakevens are indicative industry bands. Listings: all named companies are publicly listed except Continental Resources, Aethon and Hilcorp (privately held) and Pemex (Mexican state-owned). Shale figures are new-well (full-cycle) breakevens, while the oil sands ~$27 is a half-cycle cost of running existing operations and the $80+ a greenfield full-cycle breakeven — Section 9 explains why they are not comparable.

3.1 The shale oil engines

The Permian Basin is the most important oil basin in the Western Hemisphere. It is two basins under one name — the Midland and the Delaware, split by the Central Basin Platform — and its edge is stacked rock: a dozen productive benches that let an operator drill many horizontal wells from one pad, plus the deepest inventory and best infrastructure of any US basin. Its binding constraint is associated gas — 27.5 Bcf/d of it — whose pipeline takeaway, not geology, often caps activity.

The other oil plays differ less in rock than in maturity and constraint. The Bakken is the original tight-oil play, still one of the best barrels but with fewer undrilled locations; the Eagle Ford’s zonation — oil updip grading into condensate and dry gas down-dip — lets operators steer between products; and in the smaller plays the binding constraint is above ground or in the barrel: Colorado’s permitting in the DJ Basin, the Powder River’s unrealised multi-bench potential, heated transport for the Uinta’s waxy crude.

3.2 The gas engines & legacy basins

Appalachia — the Marcellus and the deeper Utica — is the continent’s dry-gas heartland at 36.7 Bcf/d, with the lowest US gas breakevens, but it can produce more than its pipelines carry, so local prices trade below Henry Hub, the Louisiana hub that sets the US gas benchmark, and new supply waits on new pipe. The Haynesville is hotter, deeper and dearer, and its strategic case is proximity to Gulf Coast LNG. The Barnett, Fayetteville and San Juan no longer grow but produce cheaply on sunk infrastructure.

3.3 Canada & Mexico onshore

Canada’s onshore is a different animal. The Alberta oil sands hold about 159 billion barrels of bitumen and produce 3.5 MMbbl/d: shallow deposits are mined, deeper ones melted in place by SAGD or CSS steam (mechanics in the oil sands guide). The economics invert shale — huge up-front capital, then decades of near-flat output — and the product is sold heavy and sour as WCS or upgraded to light synthetic crude. The Montney’s condensate, bought back as bitumen diluent, lifts otherwise cheap gas economics; the Duvernay is its younger cousin; and the conventional and heavy WCSB — light-oil waterfloods, Clearwater multilateral wells, Lloydminster CHOPS — adds about 1.1 MMbbl/d.

Mexico’s onshore is small and almost entirely Pemex: Burgos extends the south-Texas gas trend, and Chicontepec holds vast oil in rock so tight that decades of drilling have produced little.

Figure 3. North American crude oil production by major source (2025)

Figure data: US regions and the Gulf of America per the U.S. EIA Short-Term Energy Outlook, September 2026 (Bakken 1.23, Eagle Ford 1.16); Canadian oil sands and conventional oil per CAPP, 2025; Mexico is Pemex plus partners, 1.635 MMbbl/d including 268 kbbl/d of condensate and onshore output, per Pemex 4Q25 results as reported by Mexico Business News.

Figure 4. North American natural gas production by region (2025)

Figure data: US regions per the U.S. EIA Short-Term Energy Outlook, September 2026, Table 5a (marketed gas, 2025 averages); Anadarko per Novi Labs, November 2025, horizontal wells only (a lower bound); Western Canada is the approximate WCSB total including the Montney per the Canada Energy Regulator and CAPP (Canada about 18.8 Bcf/d, 2025 year to date).

3.4 Offshore North America

Offshore North America is a few basins with an outsized share of the capital and reserve life: the US Gulf of America, Mexico’s Bay of Campeche and the Grand Banks. Their deposits are conventional — the difficulty is the water, not the rock.

Table 4. North American offshore basins — deposit characteristics, production and operators

Source: Gulf of America output per U.S. EIA, March 2026, and operator lists per BOEM; Thunder Horse, Hibernia and Hebron assays per ExxonMobil; Mars, Maya and Isthmus per the S&P Global Platts Americas crude specifications, July 2026; Campeche output is crude production by business unit per Pemex’s 2025 annual report on Form 20-F — Ku-Maloob-Zaap 530.5 kbbl/d (585.2 in 2024) and Cantarell 123.4 kbbl/d, of which the Cantarell fields proper 51.8 kbbl/d, against a 2004 peak of 2.1 MMbbl/d per Offshore Technology; Trion per Woodside; Newfoundland output derived from its 4.5% share of Canada’s 5.35 MMbbl/d per the Canada Energy Regulator, 2025. Listings: all named companies are publicly listed except Pemex (state-owned) and Arena (private). Water depths and reservoir descriptions are structural, not point-in-time.

The Gulf of America is the continent’s offshore workhorse: at ~1.9 MMbbl/d it outproduces every US onshore basin except the Permian, and it grew by 111 kbbl/d in 2025 as five deepwater projects started. Its traps owe their shape to moving salt, its giants — Mars, Thunder Horse, Atlantis — produce medium, partly sour crude for decades from floating hubs, and it grows mainly by subsea tieback. For an investor it is the long-cycle complement to shale: projects sanctioned years earlier keep producing through a price dip that stops shale drilling within months.

Mexico’s production is overwhelmingly offshore, heavy and sour. Cantarell — a carbonate breccia shattered at the end of the Cretaceous, which peaked above 2 MMbbl/d in 2004 — has fallen below 6% of that despite the world’s largest nitrogen-injection scheme, and Ku-Maloob-Zaap is past its peak too; Trion and Zama arrive late this decade. Off Newfoundland, iceberg-resistant gravity-base platforms and FPSOs produce light oil from the Jeanne d’Arc Basin, with the ultra-deep Flemish Pass next door.

4. South & Central America

South America holds the world’s largest reserves, in Venezuela’s extra-heavy Orinoco Belt, and its fastest-growing deepwater basins, off Brazil and Guyana — plus Argentina’s Vaca Muerta, the one shale-oil play outside North America producing at scale. It spans the whole range of Table 1, from cold-produced tar to ultra-deep FPSOs.

Table 5. South & Central American basins — deposit characteristics

Source: Orinoco resource and recovery basis per the USGS, 2009, and Merey 16 per the S&P Global Platts Americas crude specifications, July 2026; Maracaibo geology per Wikipedia’s Maracaibo Basin article; pre-salt assays per PPSA, 2025, and gas re-injection per JPT, 2024; Marlim per Wikipedia’s Marlim article; Stabroek geology per AAPG Search and Discovery and assays per ExxonMobil; Vaca Muerta per Wikipedia’s Vaca Muerta Formation article and Medanito assay per Equinor via Oil & Gas Journal, 2023; Castilla per U.S. EIA. Crude qualities are blend specifications; Merey’s varies with how much diluent is blended in.

Table 6. South & Central American basins — production, reserves, operators and terms

Source: Brazil output per the ANP December 2025 production bulletin and reserves per the ANP, April 2026; Petrobras costs per its 4Q25 report; fiscal regimes per the ANP; Venezuela 2025 output per the U.S. EIA Short-Term Energy Outlook, September 2026, Table 3c (1.01 MMbbl/d total liquids), and April 2026 output per OPEC secondary sources (1.031 MMbbl/d) and PDVSA (1.136 MMbbl/d) as compiled by Venezuelanalysis (sources disagree on 2026 levels), reserves per U.S. EIA and OPEC, law changes per Mayer Brown, February 2026, Chevron’s joint ventures per World Oil and its “total costs of less than $20 per barrel” per Chevron, 2 September 2026 (components not itemised); Guyana per ExxonMobil, the Guyana government via OilNOW (261.1 MMbbl in 2025; U.S. EIA estimates ~750 kbbl/d) and breakevens per OilNOW; Argentina per Secretaría de Energía data compiled by Río Negro (gas converted from 76 MMm³/d), reserves per U.S. EIA and well breakevens per Rystad Energy, May 2026, which does not state their price basis; Colombia figures are approximate and should be re-sourced from the ANH; Suriname per TotalEnergies, October 2024. Listings: PDVSA is state-owned; Pan American Energy and Tecpetrol are privately held.

4.1 The Orinoco Belt

Venezuela’s Orinoco Oil Belt is the biggest oil accumulation on Earth — about 1.3 trillion barrels in place, 513 billion technically recoverable on the USGS mean estimate — and one of the least productive. It is the same accident as Athabasca: crude migrated to a shallow, cool basin margin where bacteria ate its light molecules. But it is warm enough to move, so it is produced cold through horizontal wells and pumps, then blended with imported naphtha into Merey 16 or upgraded to synthetic crude — making every barrel dependent on a diluent supply chain. National output fell from about 3 MMbbl/d around 2000 to near 0.35 MMbbl/d in 2020 and has recovered toward 1 MMbbl/d since US licensing resumed: the largest reserves in the world are worth only what above-ground conditions let them produce.

4.2 Brazil’s pre-salt

Brazil’s pre-salt is the region’s growth engine: Early Cretaceous microbial carbonates formed in rift lakes as South America tore from Africa, sealed under about two kilometres of salt in two kilometres of water. Hard to image and undrilled until the mid-2000s, the reservoirs proved thick — up to 480 metres at Búzios — and full of light-to-medium sweet crude, developed entirely through FPSOs. The complication is CO₂-rich associated gas, mostly re-injected rather than sold. The result is one of the lowest deepwater lifting costs anywhere — about $4/boe for Petrobras — against four times that in the mature, heavier Campos post-salt fields next door, and inside the pre-salt polygon production-sharing contracts give the state a bid share of profit oil.

4.3 Guyana–Suriname

Guyana is the fastest deepwater ramp in the industry’s history: from first oil in December 2019 to more than 900 kbbl/d in November 2025, with the operator targeting about 1.7 MMbbl/d by 2030. Stabroek’s reservoirs are Upper Cretaceous turbidite sandstones — West Africa’s mirror image, because the margins were once joined — developed by a repeatable programme of 250 kbbl/d FPSOs with project breakevens around $25–35/bbl. The risk is concentration in one block and one production-sharing agreement whose initial cost pool has been recovered, so the state’s share of output is rising. Suriname’s Block 58 follows in 2028.

4.4 Vaca Muerta

Argentina’s Vaca Muerta is one of the world’s best shale source rocks — thicker than most US plays and over-pressured — and shale oil reached about half a million barrels a day in 2025, lifting national crude to 0.80 MMbbl/d, just short of its 1998 peak of 0.82. It behaves like a North American shale (light sweet Medanito, oil-to-gas windows, 3,000-metre laterals) and declines like one. The difference is above ground: provincial royalties, capital controls and a lagging pipeline network, which is why the VMOS export line and the RIGI investment regime matter as much as the rock.

5. Europe & the Caspian

Europe’s producing basin is the North Sea, home of the Brent benchmark. East of it, Russia’s West Siberian and Volga-Ural basins make the country the third-largest oil producer, and the Caspian adds some of the deepest, highest-pressure and most sour conventional reservoirs anywhere. Few regions show more clearly how much the terms around a deposit matter.

Table 7. Europe & Caspian basins — deposit characteristics

Source: Norwegian field geology, water depths and recovery per Norsk Petroleum field pages and the Norwegian Offshore Directorate; UK per the NSTA and operator pages (Ithaca Energy); Russian basins per U.S. EIA and the Oxford Institute for Energy Studies, 2024; Tengiz per the Tengizchevroil year-end 2025 fact sheet (sour-gas injection completed 2008), depth per an AAPG conference abstract (“buried to a depth of 4000 m”), formation pressure (11,110 psi), oil column (over 1,500 m) and Permian salt seal per the Oil & Gas Journal, 1990, and 17% H₂S per Fluor, the sour-gas plant’s contractor; Kashagan and ACG per operator disclosures (bp Azerbaijan); all crude specifications per the S&P Global Platts EMEA crude specifications and Asia Pacific crude specifications (ESPO, Sokol, Sakhalin Blend), August 2026. Company assays differ slightly — Equinor’s 2026 Troll assay reads 38.8° API — so treat single values as blend specifications.

Table 8. Europe & Caspian basins — production, reserves, operators and terms

Source: Russian oil output per Deputy Prime Minister Novak (“516 million tonnes”, converted at ~7.3 bbl/t) as reported by Interfax, December 2025 (Russia withholds official statistics), and gas per the Energy Institute Statistical Review of World Energy 2026 via Our World in Data (609 bcm in 2025, converted to Bcf/d on the same basis as Table 10), reserves per the Oil & Gas Journal worldwide survey (1 January 2026) and U.S. EIA citing Rystad, price cap per the European Commission and sanctions per the U.S. Treasury; Kazakhstan per its statistics bureau via The Astana Times, OGJ and the Tengizchevroil year-end 2025 fact sheet; Norway per the Norwegian Offshore Directorate (remaining reserves derived from its end-2025 resource accounts), taxes per Norsk Petroleum, Johan Sverdrup’s emissions per Equinor and its 2026 decline guidance per Equinor’s chief executive as reported by JPT, February 2026 (a forecast); UK per DESNZ, the NSTA and Deloitte; Azerbaijan per bp and OGJ. Moscow-listed shares are not tradable for most Western investors. Oil output bases differ by country — crude only, crude and condensate, or including NGLs — as labelled.

5.1 The North Sea

The North Sea is a Jurassic rift full of tilted fault blocks — sandstone reservoirs rotated and sealed along faults — plus the fractured chalk of Ekofisk, in water shallow enough for fixed platforms. Norway is at a plateau, its oil output the highest since 2009 on Johan Sverdrup and Johan Castberg, and a special tax that expenses investment immediately keeps companies drilling despite the 78% rate. The UK is in structural decline, and a 78% headline rate after the Energy Profits Levy lost its investment allowance has pushed majors toward exits and joint ventures: fiscal design, more than geology, now decides which half of a shared basin gets reinvestment.

5.2 Russia

West Siberia is Russia’s oil engine and largest gas province: Samotlor, found in 1965, still produces under waterflood at water cuts above 90%, newer fields rely on fractured horizontal wells, and the dry-gas giants of Urengoy and Yamal feed pipelines and Yamal LNG. The older Volga-Ural basin’s heavy, high-sulphur crude turns Siberian Light into medium-sour Urals, while East Siberia and Sakhalin face Asia. For an investor the wrapper matters more than the rock: Western-held shares are frozen, sanctions and the price cap set the discount, and statistics are withheld.

5.3 The Caspian

The Caspian’s giants are deep, over-pressured carbonates under thick salt, full of light crude and sour gas. Tengiz holds an oil column over 1.5 kilometres tall about four kilometres down and re-injects its hydrogen-sulphide-rich gas; Kashagan, in shallow water that freezes in winter, was built on artificial islands and became a byword for overruns after sour-gas corrosion forced its pipelines to be replaced. Kazakh output rose 13% in 2025, but almost all of it leaves through the CPC pipeline across Russia — a single route drone strikes interrupted twice that year. Azerbaijan’s Azeri-Chirag-Gunashli is the mature, light sweet counterpoint, exported through BTC to Turkey.

6. Middle East

The Middle East is where every condition of the petroleum system lined up at once, over an area no other region matches. The result is a cluster of supergiant conventional fields that flow on their own pressure, are held up by water or gas injection, decline slowly and lift for a few dollars a barrel. Two provinces matter: the Arabian Basin, a broad platform of Jurassic and Cretaceous reservoirs under Saudi Arabia, Kuwait, the UAE, Qatar and southern Iraq, and the Zagros fold belt of Iran and northern Iraq, where the same rocks were crumpled into giant anticlines. Nearly all of it is state-owned, and most of it ships through the Strait of Hormuz.

Table 9. Middle East basins — deposit characteristics

Source: Saudi field geology per Wikipedia’s Ghawar Field article and Aramco (Jafurah); Manifa per Offshore Technology; Saudi grades per S&P Global (Arab Light) and Wikipedia’s list of crude oil products (Arab Extra Light, Arab Heavy, Kirkuk, Iran Light, Kuwait Blend — re-source from national marketing specifications before relying on them); Oman Blend per the S&P Global Platts Asia Pacific crude specifications, August 2026; Basrah grades per SOMO via S&P Global, 2020; Iraq water injection per U.S. EIA; Zagros per Wikipedia’s Zagros fold and thrust belt article; Burgan per GEO ExPro; Murban per U.S. EIA (Platts data), July 2026; Upper Zakum per the ExxonMobil Upper Zakum assay, January 2026, the basis used across this series (U.S. EIA and Platts give 33.2° · 2.09%); North Field per U.S. EIA; Oman per bp, Petroleum Development Oman (ownership; thermal, chemical and gas EOR) and Wikipedia’s Petroleum Development Oman article. Iraqi reservoir units and Oman field-by-field methods are simplified to the basin level.

Table 10. Middle East producers — production, reserves, operators and terms (2025 pre-disruption baselines)

Source: total liquids per the U.S. EIA Short-Term Energy Outlook, September 2026, Tables 3a–3c (2025, including NGLs); Aramco production, reserves, lifting cost, royalty and ownership per its 2025 results and 2025 annual report legal section; gas output per the Energy Institute Statistical Review of World Energy 2026 via Our World in Data, converted to Bcf/d; country reserves per the OPEC Annual Statistical Bulletin 2026 (end-2025), with the U.S. EIA’s 145 bn bbl for Iraq and 111 bn bbl for the UAE shown as the other end of each range; Iraq contracts and pipeline per U.S. EIA and Iraq Business News; UAE capacity, OPEC exit and bypass pipelines per U.S. EIA, June 2026; Qatar per U.S. EIA and the IEA (Hormuz share of LNG exports; its 2026 status is in Section 6.3); Oman per bp. 2026 output is sharply below these 2025 baselines because of the Hormuz disruption. Listings: NIOC, Basra Oil Company, KOC, QatarEnergy and ADNOC are state-owned and unlisted.

6.1 The Arabian Basin supergiants

Ghawar is the archetype: one Late Jurassic limestone reservoir along a 280-kilometre fold, producing since 1951, its pressure held up by peripheral seawater injection since 1965. The template repeats across the basin — Kuwait’s Burgan sandstone on natural water drive, Abu Dhabi’s Upper Zakum drilled from artificial islands — and these barrels sit at the bottom of the world cost curve: Aramco lifted oil and gas for $3.51/boe in 2025. Capacity that cheap and that slow to decline can sit idle at little cost, which is why most of the world’s spare capacity — output restorable within weeks — is here (Table 10’s capacity and output rows). Qatar’s North Field, shared with Iran as South Pars, is the largest gas-condensate accumulation in the world, and Saudi Arabia’s Jafurah is the region’s first large unconventional gas development.

6.2 Iraq & the Zagros

Southern Iraq’s Rumaila, West Qurna and Majnoon are Arabian Basin supergiants with a poorer barrel — medium-heavy Basrah crude at 3–4% sulphur — whose growth depends on injecting enough water to hold pressure, and whose foreign partners earn a fixed service fee per barrel rather than oil. In the Zagros fold belt, Kirkuk, Kurdistan and Iran’s Ahvaz, Marun and Gachsaran produce mainly through natural fractures in Asmari limestone anticlines — and here above-ground risk dominates: Kurdistan’s exports were shut in for two and a half years by a pipeline dispute, and Iran’s fields sit under sanctions and, since February 2026, war.

6.3 Oman & the Hormuz factor

Oman is the Gulf’s mature-field laboratory, running thermal, polymer and gas enhanced oil recovery — including solar-generated steam at Amal — and tight-gas fracturing at Khazzan, and it exports from outside Hormuz. That matters, because the region’s biggest above-ground risk is now realised: after the conflict involving Iran began on 28 February 2026 the strait effectively closed, and flows through it fell from about 21.6 MMbbl/d in late 2025 to 4.9 MMbbl/d in the second quarter of 2026, according to the U.S. EIA’s August 2026 outlook, with producers that have bypass pipelines shutting in less. Qatar’s LNG has no bypass: Ras Laffan has been largely offline since an attack on 2 March 2026 (status at September 2026). The cheapest barrels in the world are also the most exposed to a single chokepoint.

7. Africa

Africa’s oil comes from two kinds of basin: North Africa’s onshore desert rifts and platforms, full of light, very sweet crude and, in Algeria, gas piped to Europe; and West Africa’s deltas and deepwater slopes, the geological twins of Brazil and Guyana, developed with FPSOs. In both, above-ground risk has mattered as much as the rock.

Table 11. African basins — deposit characteristics

Source: Sirte geology per Wikipedia’s Sirte Basin article, citing the USGS; Libyan and Nigerian assays per TotalEnergies crude assays (Es Sider 2018, Sharara 2020, Bonny Light 2020, Bonga 2015, Egina 2019) and ExxonMobil (Qua Iboe 2024; Pazflor 27 March 2026, which replaced a 2024 assay); Algeria per AAPG Bulletin, U.S. EIA (Saharan Blend 43.2° · 0.10%; other compilations give ~45°) and Oxford Business Group; Zohr per Eni; Agbami per U.S. EIA; Angola per ExxonMobil, TotalEnergies and TotalEnergies assays (Girassol, Dalia 2015); Sangomar per Woodside; Namibia per Galp. The Niger Delta trap description is the standard regional model rather than a field-by-field assessment.

Table 12. African producers — production, reserves, operators and terms

Source: Nigeria and Algeria total liquids per the U.S. EIA Short-Term Energy Outlook, September 2026, Table 3c (2025); Nigeria’s reserves per the NUPRC (37.01 bn bbl and 215.19 Tcf at 1 January 2026) and its crude-only average per NUPRC data as reported by Oilfield Technology, fiscal terms per Morgan Lewis and Seplat cost per its full-year 2025 results; Algeria per U.S. EIA and IBA, with gas per the Energy Institute Statistical Review of World Energy 2026 via Our World in Data (98 bcm, converted to Bcf/d); Libya per the National Oil Corporation via Libya Observer, U.S. EIA and Libya Analysis; Angola per U.S. EIA and Mayer Brown; Egypt per U.S. EIA and Eni; reserves for Algeria, Libya, Angola and Egypt per the Oil & Gas Journal as republished by U.S. EIA; Senegal per Woodside; Namibia per Galp. Output bases differ by country, as labelled.

7.1 North Africa’s desert basins

Libya holds Africa’s largest oil reserves in the Sirte Basin, a rift broken into tilted, uplifted fault blocks (horsts), and the Murzuq Basin, whose Sharara crude is among the lightest and sweetest traded. Geology is not the constraint — politics is: output fell below 0.6 MMbbl/d in the 2024 central-bank crisis and recovered to a decade-high 1.37 MMbbl/d in 2025. Algeria is mature and gas-heavy: Hassi Messaoud relies on gas injection, and the Hassi R’Mel gas-condensate supergiant anchors pipelines to Italy and Spain, but rising domestic demand is shrinking exports. Egypt tells the gas version: Zohr, a Miocene reef with a 630-metre gas column in the deepwater Nile Delta, is declining — national gas output fell 17% in 2024 — and that decline has turned the country into a gas importer.

7.2 West Africa’s deltas & deepwater

The Niger Delta is a textbook delta: Tertiary sandstones deformed by growth faults — faults that slipped while sediment was still piling up, rolling the sands into traps — hold light sweet oil onshore and in the swamps, and Miocene turbidites carry the play into deep water. Onshore Nigeria has been hollowed out by crude theft, and the majors have sold onshore joint ventures to local independents such as Seplat while keeping deepwater FPSO fields, which are beyond the pipeline thieves and pay lower royalties under the 2021 Petroleum Industry Act. Angola’s output comes almost entirely from deepwater Oligo-Miocene turbidites above the salt, produced by FPSOs and declining without new projects; the pre-salt, Senegal’s Sangomar and Namibia’s Orange Basin are the frontier — Sangomar producing since June 2024, Namibia’s Venus discovery planned around a 160 kbbl/d FPSO but still short of a final investment decision.

8. Asia Pacific

Asia Pacific is the largest oil-importing region and a modest producer, but an instructive one: China runs some of the world’s largest enhanced-recovery projects, Asia’s deepest wells and the largest shale-gas industry outside North America; Australia is almost purely a gas-for-LNG province; and Southeast Asia combines mature waxy crudes, a giant steamflood and oil in fractured granite.

Table 13. Asia Pacific basins — deposit characteristics

Source: all crude specifications per the S&P Global Platts Asia Pacific & Middle East crude specifications, August 2026; Daqing per CNPC and PetroChina via GlobeNewswire; Bohai per Global Times; Ordos per China Daily; Tarim per CGTN and Offshore Technology; Sichuan per Energy Geoscience; Junggar per Xinhua; South China Sea per CNOOC; Australian basins per Geoscience Australia, Chevron and INPEX; Malaysia per PETRONAS and Offshore Technology; Indonesia per Global Energy Monitor and ExxonMobil, with Duri’s steamflood (“since 1985”, “one of the largest steamflood developments in the world”) per Chevron, 2018; Bach Ho per Wikipedia’s Bach Ho oil field article. Reservoir descriptions are simplified to the basin level.

Table 14. Asia Pacific basins — production, reserves, operators and terms

Source: China national output per the National Bureau of Statistics via Hydrocarbon Processing (converted at 7.3 bbl/t); PetroChina lifting cost per its 2025 annual results and CNOOC per its 2025 results release; Changqing per Global Times (51.42 bcm of gas in 2025); Bohai per Global Times; Daqing per CNPC and Wikipedia’s Daqing Oil Field article (crude rate dated 2021); Tarim per CGTN; Australian reserves and coal-seam gas output per Geoscience Australia (end-2024); LNG capacities per Chevron, Woodside, INPEX, INPEX (Prelude, 3.6 Mtpa), Santos and the U.S. EIA Australia brief; Woodside cost per its 2025 results and Santos per its fourth-quarter 2025 report (“below $7/boe (excluding Bayu Undan)”); resource rent tax per PwC; Indonesia per SKK Migas via Antara; Malaysia per DOSM and PwC; reserves for Indonesia, Malaysia and Vietnam and Vietnam’s output per the Oil & Gas Journal worldwide survey, 1 January 2026. China’s basin rows are reported in tonnes of oil equivalent and are not additive to the national total; PETRONAS, Pertamina and PetroVietnam are state-owned and unlisted.

8.1 China

Many of China’s basins are lake-deposited (lacustrine) rift and foreland basins, giving oil that is waxy, low in sulphur and in places heavy, in reservoirs that are mature, tight or very deep. Daqing, discovered in 1959, has produced for over sixty years with water, then polymers and surfactants, and now runs at about 95% water cut — one of the world’s largest polymer-flooding operations. Growth has moved to the Ordos Basin’s tight oil and gas (Changqing added more than 1,900 wells in 2025), the Tarim Basin’s carbonate caverns below 8,000 metres, the Sichuan Basin’s Longmaxi shale gas and offshore Bohai. All of it is produced by three state-controlled listed companies at costs well above the Gulf’s.

8.2 Australia

Australia’s hydrocarbons are overwhelmingly gas. The offshore Northern Carnarvon, Browse and Bonaparte basins hold gas and ultra-light condensate piped to onshore LNG plants or, at Prelude, liquefied at sea; onshore Queensland’s Bowen-Surat coal-seam gas comes from thousands of shallow dewatered wells feeding three LNG plants on Curtis Island. The deposits bring their own costs — Gorgon’s gas is about 15% CO₂, which is separated and re-injected — and a 40% resource rent tax on project profits.

8.3 Southeast Asia

Southeast Asia is a region of mature Tertiary basins. Malaysia’s Tapis is one of the lightest, sweetest crudes in the world and its gas feeds Bintulu LNG; Indonesia’s Duri has produced heavy but low-sulphur oil by steamflood since 1985 — thermal recovery on a conventional reservoir, unlike Alberta’s oil sands; and Vietnam’s Bach Ho stores its oil in fractured granite. The region runs on production-sharing contracts with state companies, and its oil output is in long decline even as gas stays strategic.

9. What drives basin economics

Every regional table reduces to one question: what does a barrel cost here, how much of its price does the producer keep, and how long does it last? Five drivers set the answer, all of them basin traits (production-cost anatomy is in the cost guide; the global cost curve in Part 1: Upstream, “The cost curve & breakevens”).

1. Hydrocarbon window and crude quality. Oil is worth several times an energy-equivalent unit of dry gas, and light sweet crude more than heavy sour, so condensate-rich or light-crude basins can carry costs that would sink a dry-gas or bitumen project — and the quality gap in Figure 2 is permanent.
2. Reservoir quality and depth. Thick, permeable, over-pressured rock (Ghawar, the pre-salt) flows at high rates from few wells; tight rock needs many fractured wells; ultra-deep rock (Tarim, Kashagan) needs expensive ones.
3. Extraction method and decline. Shale must be re-drilled continuously; deepwater commits billions up front, then holds a plateau; waterflooded supergiants decline a few per cent a year; oil sands barely decline — cheap-and-fast-declining against expensive-and-durable.
4. Fiscal regime and ownership. A concession barrel is owned and taxed, a production-sharing barrel is shared after cost recovery, and a service contract pays a fee — so the same deposit is a different investment in Norway (78% marginal tax, investment expensed), Guyana (2% royalty, 50/50 profit oil) or southern Iraq (a dollar or two per barrel).
5. Above-ground access. Takeaway (Appalachia, Vaca Muerta), export routes (CPC, Hormuz), sanctions (Russia, Iran, Venezuela) and security (Libya, the Niger Delta) decide how much of a basin’s potential reaches a market.

Table 15 lines up the published cost indicators by the bases defined in Table 1 — ranking basins on one mixed column is the commonest mistake.

Table 15. Published cost indicators across the world’s basins, by what they measure

Source: Aramco 2025 results; Petrobras 4Q25 report; Woodside 2025 results and Santos fourth-quarter 2025 report (excluding Bayu-Undan); PetroChina 2025 annual results; Seplat full-year 2025 results; NSTA benchmarking, 2024; Chevron per its September 2026 release (“total costs of less than $20 per barrel”); CNOOC 2025 results release; oil sands half-cycle per S&P Global Commodity Insights, June 2025, and greenfield SAGD per Enverus as cited in Part 1: Upstream, “The cost curve & breakevens”; Guyana per OilNOW; Vaca Muerta per Rystad Energy, May 2026; US shale per the Dallas Fed Energy Survey, March 2025, and March 2026. Rows are grouped by what the number measures — operating costs, then all-in and total costs, then half-cycle breakevens (keeping existing wells and plants running) and full-cycle breakevens (new wells and projects) — and ordered cheapest first within each group, as on a cost curve; values in different groups are not comparable. The Vaca Muerta row sits apart because its source does not state its basis; company-defined costs follow each company’s own definition.

9.1 Cheap to lift is not cheap to find

Table 15 makes Table 1’s last row concrete. Aramco’s $3.51 and Petrobras’s $4.19 are lifting costs: they keep existing wells flowing. The Permian’s $65–67 is a new-well (full-cycle) breakeven that prices the next barrel, which governs shale because output falls unless drilling continues. Guyana’s $25–35 and greenfield SAGD’s $80-plus are project full-cycle breakevens that include the up-front capital, so a deepwater province with a $4 lifting cost can need many times that to justify a new project. The durable ranking has two axes: what the next barrel costs to find and develop, and how long it flows once the money is spent — with the fiscal regime deciding how much of the difference the company keeps.

10. How to read an E&P by its basins

Bring it together at the screen: a producer is a weighted average of the basins it holds, so start with the basin map, not the share price.

A basin-first checklist for any E&P, anywhere:

1. Where is the acreage? A Permian shale producer, a pre-salt partner, an oil sands integrated and a North Sea taxpayer are four different businesses — do not compare them on one multiple (Sections 3–8).
2. Which window, and which crude? Light sweet streams (Bakken, Brent, Guyana) earn near the benchmark; heavy sour ones (WCS, Maya, Merey, Basrah Heavy) earn a structural discount; condensate and NGLs price on their own curves (Table 1, Figure 2).
3. How is it produced? Shale needs continuous capital, deepwater up-front capital, waterflooded supergiants little, and thermal or extra-heavy barrels energy and diluent (Table 1; each region’s deposit table).
4. Where does it sit on the cost curve — and which cost is quoted? Use Table 15, and never set a lifting cost against a breakeven (Section 9.1).
5. How long is the runway? Count years of quality inventory or reserves at the current decline, not this year’s output (Table 1’s decline row).
6. Who else owns the barrel? A concession barrel, a production-sharing barrel and a service fee are three different exposures to the same oil price (Section 9, driver 4).
7. What is the above-ground risk? Takeaway, export routes, sanctions, security and chokepoints can matter more than the rock (Section 9, driver 5).

The checklist at work — two hypothetical producers. Producer A holds US shale oil in the Permian plus Haynesville gas; Producer B holds a minority stake in Brazilian pre-salt fields. Both are hypothetical illustrations built from this guide’s basin figures, not real companies. Table 16 runs the seven questions.

Table 16. The basin-first checklist applied to two hypothetical producers

Source: hypothetical illustration; every basin figure is taken from Tables 1, 2, 3, 5, 6 and 15 of this guide, with the sources and vintages given there. Not the profile of any company.

The answers split at question 1 and never rejoin. A is a short-cycle drilling business priced on a new-well breakeven, with a runway measured in undrilled wells; B is a long-cycle project partner whose $4 lifting cost says little about the next FPSO’s return, and whose share of each barrel is set by contract. One multiple for both would set a running cost against a breakeven.

This is a framework for reading the business, not investment advice — and it is the sieve the Metal Pilot upstream screener is built around. To rank producers by basin, production, reserve life, netback and cost, screen them on Metal Pilot’s upstream oil & gas stock screener.

11. Summary

The world’s oil and gas comes from a few dozen basins that matter, and the basin — not the company — sets a barrel’s quality, extraction method, cost, decline and running room. Beyond the filings’ four cuts, this guide reads every basin on the same deposit parameters: reservoir and trap, API gravity and sulphur, extraction method, production system, decline and fiscal regime.

North America is the continent of variety: the Permian’s stacked shale makes 48% of US crude, Appalachia is the dry-gas heartland, the oil sands hold about 159 billion barrels of long-life bitumen, and the Gulf of America adds 1.9 MMbbl/d of deepwater oil while Mexico’s heavy Campeche giants decline. South America pairs the largest reserves in the extra-heavy Orinoco with the fastest deepwater growth in the pre-salt and Guyana, and Vaca Muerta shale. Europe and the Caspian set the mature, heavily taxed North Sea against sanctioned West Siberia and the deep, sour carbonates of Tengiz and Kashagan. The Middle East’s supergiants hold about 55% of proved crude reserves at the lowest lifting costs on Earth — and, as the still-unresolved 2026 disruption shows, the greatest chokepoint exposure. Africa trades light sweet desert crude and deepwater turbidites against above-ground risk, and Asia Pacific combines China’s mature, tight and ultra-deep basins, Australia’s LNG gas and Southeast Asia’s waxy crudes.

The lesson is that cost and durability are basin traits — read on the right basis, because a lifting cost, an all-in cost and a breakeven measure different things — and that the terms around a deposit matter as much as the deposit. Read any producer as the weighted average of its basins, use the Section 10 checklist, and take the analysis to the company level on Metal Pilot’s upstream oil & gas stock screener.

Next in the series → Follow the barrel out of the basin with Part 2: Midstream, or go back to the wellhead mechanics in Part 1: Upstream.

12. Vocabulary

Table 17. Key terms used in this guide

Source: definitions compiled from the agencies, assays and filings cited beneath each table, Part 1: Upstream and standard industry usage.

13. Sources, methodology & disclaimer

13.1 Sources, methodology & data vintage

North America. US production from the U.S. EIA Short-Term Energy Outlook (September 2026 regional tables) and U.S. crude oil production rose in 2025; US reserves from the U.S. EIA proved reserves report (year-end 2024); breakevens from the Dallas Fed Energy Survey (March 2025 and March 2026); Canada from CAPP, the Canada Energy Regulator and the Alberta Energy Regulator; Mexico from Pemex’s 2025 Form 20-F and results as reported by Mexico Business News; offshore from BOEM and Woodside.

Rest of the world. South America from the ANP and Petrobras, ExxonMobil Guyana, Argentina’s Secretaría de Energía, the USGS and the U.S. EIA; Europe and the Caspian from the Norwegian Offshore Directorate (December 2025 production figures and The Shelf in 2025), the NSTA reserves and resources report, DESNZ, the Oxford Institute for Energy Studies and operator disclosures; the Middle East from Aramco, the U.S. EIA country analyses and the OPEC Annual Statistical Bulletin; Africa from the NUPRC, Libya’s National Oil Corporation, the U.S. EIA and operator disclosures; Asia Pacific from China’s National Bureau of Statistics, company annual reports (PetroChina, CNOOC, Woodside, Santos), Geoscience Australia, DOSM and SKK Migas. Country reserves not published by a national agency come from the Oil & Gas Journal worldwide survey (1 January 2026). Crude qualities come from the S&P Global Platts crude specifications (August 2026), ExxonMobil, TotalEnergies, Equinor, CrudeMonitor and national marketing specifications; decline benchmarks from the IEA. Operator lists are compiled from company filings and are illustrative of each basin’s principal producers, not exhaustive.

Methodology & data vintage. Basin definitions, geology, deposit parameters, extraction methods and fiscal-regime types are treated as evergreen. Production is stated as 2025 rates unless labelled, reserves as the latest published year-end, and costs with their year and basis; figures are rounded. Production bases differ by source and are labelled in each cell — crude only, crude and condensate, or total liquids including NGLs — and gas is marketed or gross as the source reports it, so country rows are not strictly additive across tables. Figures converted from tonnes use ~7.3 barrels per tonne, and gas in cubic metres uses 35.3 cubic feet per cubic metre. Crude qualities are published blend specifications or assay averages; where sources disagree the table notes it. Where an agency table could not be retrieved, a figure is taken from a named secondary report and should be re-sourced before use — notably OPEC reserve figures, some Middle East grade specifications, Colombia and parts of Russia, which withholds official statistics. Middle East 2025 figures predate the 2026 Hormuz disruption, and 2026 output is materially lower. Company listings and ownership status are structural facts, not valuations.

13.2 Disclaimer & disclosure

This guide is for informational purposes only and is not investment advice, a recommendation, or an offer to buy or sell any security. Oil and gas basin data — production, reserves, crude qualities, costs, fiscal terms and operators — are estimates as of the dates stated and change continually with drilling, prices, discoveries, sanctions, conflicts and corporate transactions; readers should verify current figures against primary sources before acting, and consider consulting a licensed financial adviser. Company tickers are given to identify operators, not to endorse them, and no position in any named company is implied. This report was prepared with AI assistance: figures were sourced from the agencies and companies cited above and reviewed for accuracy, but readers should independently verify any number they rely on. Past production and cost patterns are not a guarantee of future results.