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6. Crude Oil

Teaching rewrite of crude oil: quality, the supply chain, refining economics, supply and demand, price drivers, benchmarks, the Brent and WTI complexes, and hedging for producers, refiners, and consumers. Original wording; worked numbers recomputed. Prices are teaching values. Not investment advice.

Introduction​

Crude oil is still the world’s largest energy source — about 33% of primary energy (2019), ahead of coal (27%) and gas (24%); renewables ≈ 5%. But “crude oil” isn’t one thing: price reporters track 100+ grades, from pale straw-coloured liquids to tar. Its value lies in what a refinery can make from it — so demand for crude is really refinery demand.

This lesson covers:

  • Crude quality: API gravity, sulfur, acidity, flow
  • The supply chain, tankers, and refining — yields, gross product worth, crack spreads
  • Reserves, production, consumption, trade, security of supply
  • Price drivers: macro, supply chain, geopolitics, OPEC
  • Benchmarks (WTI, Brent, Dubai/Oman), pricing methods, cargo pricing
  • The Brent complex (Dated Brent, forwards, CFDs, futures, EFPs) and US crude (WTI, NYMEX roll, negative prices in 2020)
  • Hedging: producers (futures, basis, swaps, two-asset barriers), refiners (crack spreads, margin swaps, calendar spread options), consumers (jet fuel swaps, jet diff, regression hedges, compound options)

6.1 What makes crude valuable​

PropertyMeasureBetter for refiners
DensityAPI gravity (water = 10; higher = lighter)Light (high API) → more gasoline, kerosene
Sulfur% by weight; sweet < 0.5%, sour > 0.5%Sweet — less processing
AcidityTotal Acid Number; high > 0.7Low — acidic crudes corrode equipment
FlowViscosity; pour point (lowest flowing temperature)Low — easier to pump, store, ship
TypeParaffinic (low viscosity, flammable → lubricants); naphthenic (viscous → bitumen); intermediateDepends on target products

Light, sweet, low-TAN crudes (WTI, Brent; API ~33–45) trade at premiums to heavy, sour, acidic grades (e.g. Urals). The most common quality is medium sour (~41% of output); light sweet ~19%.

Conventional vs unconventional oil: shale oil can be light and sweet; Canadian oil sands bitumen (API 7–13, 4–6% sulfur) must be upgraded — 2 t of sand ≈ 1.25 bbl bitumen ≈ 1 bbl crude, with heavy energy and water use.

6.2 The supply chain​

flowchart LR
  U[Upstream<br/>exploration & production] --> T[Transport & storage<br/>pipelines, tankers, tank farms]
  T --> R[Refining<br/>crude → products]
  R --> D[Wholesale & retail distribution]
  D --> C[End consumers]

Players: national oil companies (NOCs) — e.g. Saudi Aramco, controlling ~75% of reserves — dwarf the international oil companies (IOCs); independents; trading houses (Vitol, Mercuria); banks.

Tanker classDWT (t)
Product tanker10,000–60,000
Panamax60,000–80,000
Aframax80,000–120,000
Suezmax120,000–200,000
VLCC (≈ 2 m bbl)200,000–315,000
ULCC (≈ 4 m bbl)320,000–550,000

Pipelines: high build cost, low running cost — preferred where available. Barges (1,000–3,000 t) move products along the Rhine, Seine, Maas, and Danube.

6.3 Refining​

Distillation cuts​

Temperature (°C)Product
< −45Gas
−45 to 35LPG
35–150Gasoline, naphtha
150–230Kerosene (jet fuel)
230–340Gas oil (diesel, heating oil)
340–400Heavy gas oil
> 400Residue / fuel oil, coke, asphalt

Then conversion (cracking: heat + pressure + catalyst turn heavy molecules into lighter, more valuable ones), treating (remove contaminants), and blending to legal specs.

Refinery gain: a 42-gallon barrel yields ~45 gallons of products because lighter products occupy more volume — but never more weight. US yields (2017): ~20 gal gasoline, 11 gal diesel, 4 gal jet per barrel.

Optimisation: gross product worth​

A refinery chooses crudes and configuration to maximise gross product worth (GPW) − crude cost.

Worked example: a European refinery can run Forties (USD 64.15) or Oseberg (USD 63.45). Product prices (USD/t) and conversion factors (bbl per t):

ProductPrice (USD/t)bbl/tForties yieldOseberg yield
Gasoline5588.3535%25%
Jet5827.8810%15%
Gas oil6157.4620%15%
Fuel oil3506.3535%45%

Revenue per barrel = price ÷ factor × yield (e.g. gasoline from Forties = 558 / 8.35 × 35% = 23.39).

FortiesOseberg
Gasoline23.3916.71
Jet7.3911.08
Gas oil16.4912.37
Fuel oil19.2924.80
GPW66.5564.95
− Crude cost64.1563.45
Margin2.401.50

Choose Forties — dearer crude, better margin. In theory a grade’s differential to a benchmark equals the difference in product-slate value: the discount at which the refiner is indifferent.

Crack spreads​

Price reporters publish indicator margins (US Gulf Coast sour cracking, Singapore hydrocracking, NW Europe light sweet cracking).

3-2-1 crack: 3 bbl crude → 2 bbl gasoline + 1 bbl heating oil (distillate). Crude USD 50, gasoline USD 1.40/gal, heating oil USD 1.20/gal:

Crack = ⅔ × 1.40 × 42 + ⅓ × 1.20 × 42 − 50 = 39.20 + 16.80 − 50 = USD 6.00/bbl

Note on the source

The source rounds the weights to 0.67/0.33 (giving 6.03) and calls the third leg “fuel oil” while pricing heating oil. The 3-2-1 crack uses gasoline and heating oil (distillate) with exact ⅔ and ⅓ weights.

Drivers of refinery profit: internal — product slate value, crude choice, configuration, reliability, location, specialty products, costs, own stocks; external — product demand, market inventories, seasonality, crude prices, trade, substitution, specs, technology, gasoline vs diesel demand, weather.

Checkpoint 1: quality and refining​

Quiz

Checkpoint — sections 6.1 to 6.3

1 / 5

A crude has API 22 and 1.8% sulfur. It is…

Pick an answer to see if you are right.

6.4 Demand and supply​

  • Proved reserves rose from ~684 bn bbl (1980) to ~1,734 bn (2019) — higher prices and technology turn resources into reserves. Middle East ≈ ½; South & Central America (largely Venezuela) ≈ 19%.
  • R/P ratio (reserves ÷ annual production) ≈ 50 years in 2019 (≈ 41 in 2004) — a snapshot, not a countdown.
  • Production ≈ 95 m bbl/day (2019); Middle East ≈ 32%, North America ≈ 26% after the shale boom (US output fell from 1970 to 2008, then surged past 13 m bbl/day).
  • Consumption: Asia Pacific ≈ 37%; China ≈ 14% of world demand.
  • Mismatch between reserves, production, and consumption drives trade (Middle East and West Africa → Europe, US, China).
  • Security of supply (importers diversify sources) and security of demand (exporters diversify buyers).
  • Brent’s own field output fell from ~2.9 m bbl/day (1999) to ~1.1 m (2019) — hence a widened basket.

6.5 Price drivers​

GroupDrivers
MacroGDP growth; reserves and recovery technology (typical recovery ~30%); strategic reserves (US SPR, capacity ~700 m bbl); substitution (gas, biofuels, EVs, hydrogen); differentials to markers; refined product demand (heating oil in winter, gasoline in the US driving season); taxation (European diesel incentives); transport trends; investor flows (index rolls, active funds); USD; weather and hurricanes
Supply chainSpare upstream capacity (Saudi spare capacity is mostly heavier, sour crude); production costs (from ~USD 9/bbl in Saudi Arabia to ~USD 44 in the UK, 2016); rig counts and maintenance; refining capacity (US refineries fell from 325 in 1981 to ~135 by 2017; none built 1998–2014); environmental rules; crack spreads; storage and inventories; rigs, tankers, skilled labour; distribution bottlenecks; disasters (Hurricanes Katrina and Rita, 2005); field quality changes
GeopoliticsWar, terrorism, sanctions (Iraq, Iran); internal unrest; security-of-supply tensions; resource nationalism; NOCs limiting IOC access; OPEC

OPEC​

OPEC coordinates members’ output quotas to stabilise prices and income. Its influence is greatest when the market is tight; shale has reduced it. Since 2016 the wider OPEC+ alliance (including Russia) coordinates output too.

Membership update

The source lists 14 members. Ecuador left in 2020 and Angola in 2024, so OPEC now has about 12 members (Algeria, Congo, Equatorial Guinea, Gabon, Iran, Iraq, Kuwait, Libya, Nigeria, Saudi Arabia, UAE, Venezuela).

Forward curve segments​

  • 0–18 months: physical — supply/demand, inventories, storage, security of supply.
  • Beyond 18 months: financial — rates, inflation, capex expectations.
  • Oil curves are more volatile than financial ones, can be seasonal, and mean-revert long term.

6.6 Prices and benchmarks​

Quoted in USD per barrel (42 US gal ≈ 159 L). Inflation-adjusted peaks: 1864 and ~1980 (> USD 100 in today’s money).

Delivered cost = FOB price + shipping + secondary transport + losses (evaporation) + insurance + financing in transit. FOB compares crudes worldwide; buyers care about CIF.

Marker crudes​

MarkerOriginAPI / sulfur
WTIUS (Cushing, Oklahoma)39.6 / 0.24%
Brent (basket)North Sea38.8 / 0.37%
Dubai / OmanMiddle East (Asia benchmark)medium sour
UralsRussia (Mediterranean)31.7 / 1.35%

Also: Light Louisiana Sweet, Mars (US sour), and the Argus Sour Crude Index (ASCI) (Mars, Poseidon, Southern Green Canyon) used by Saudi Arabia, Kuwait, Iraq for US sales. WTI is “landlocked” at Cushing — local storage and refinery outages can distort it.

Saudi crude isn’t a global marker: after the 1980s netback pricing episode it prices by destination (WTI/ASCI for the US, Brent for Europe), bans resale, and sells on evergreen contracts.

Pricing methods​

Official selling prices · fixed price (most long-term volume) · floating (PRA averages around delivery) · differential to a marker · futures-based · exchange for physicals (EFP).

Worked example: pricing a cargo​

“Platts Dated Brent + USD 1.00/bbl, FOB, pricing 2-1-2” = average of Dated Brent on the 2 days before, the day of, and the 2 days after the bill of lading date, plus USD 1.00. For a 600,000 bbl cargo the buyer’s price exposure builds by 600,000 / 5 = 120,000 bbl per pricing day.

Checkpoint 2: drivers and benchmarks​

Quiz

Checkpoint — sections 6.4 to 6.6

1 / 5

Reserves 300 bn bbl; production 6 bn bbl/year. R/P ratio?

Pick an answer to see if you are right.

6.7 The Brent complex​

North Sea grades: Brent, Forties, Oseberg, Ekofisk, Troll (BFOET). Benchmarks are built from them; since 2023, US WTI Midland delivered to Europe has also been included in Dated Brent.

Dated BrentBrent forward (“paper”, cash BFOET)ICE Brent futures
MarketOTC physicalOTCExchange
WhatCargoes with a known 3-day loading window, 10 days to ~1 month aheadCargo in a future month, loading dates nominated laterStandard 1,000 bbl contracts
Size600,000 bbl600,000 bbl (partials smaller)1,000 bbl
SettlementPhysicalPhysical (or “booked out”)EFP or cash vs ICE Brent Index
Expiry——Last business day of the second month before delivery
  • Dated Brent is a PRA assessment (lowest-priced grade, quality-adjusted to remove “cheapest to deliver” effects), rolling daily over its 10-day-to-1-month window.
  • Forwards become “wet” when the seller nominates a 3-day laycan with at least one month’s notice (SUKO 90 terms).

Contracts for difference (CFDs)​

CFD = Dated Brent (for a future week) − third-month Brent forward. Weekly out to 8 weeks; 50,000–100,000 bbl.

Implied forward Dated Brent = CFD + third-month forward

Quote sideMarket userProfits if the differential…
OfferBuys: pays fixed, receives actualRises (more positive / less negative)
BidSells: receives fixed, pays actualFalls

Speculation: buy a CFD at +1.55; actual averages +1.75 → +0.20 × 50,000 = USD 10,000. With negative quotes the logic holds: buy at −2.05, settle at −1.85 → +0.20/bbl.

Hedge example (early March): buy a cargo loading 21–23 March, priced on average Dated Brent. Buy the 20–24 March CFD at −1.39 and go long June forward at 68.72 → implied cost 67.33.

DayDatedJune fwdDiff
Mon 2069.4870.79−1.31
Tue 2169.4970.78−1.29
Wed 2269.5070.80−1.30
Thu 2369.5170.82−1.31
Fri 2469.5270.81−1.29
  • Cargo price = average Dated 21–23 = 69.50
  • CFD: average diff −1.30 vs −1.39 → +0.09
  • June forward closed at 70.81 → +2.09
  • Net = 69.50 − 0.09 − 2.09 = 67.32 ≈ the locked 67.33 (rounding from averaging vs single close)

Exchange for physicals (EFP)​

Swap a physical position for a futures position, quoted as a differential (time, quality, location).

Example: a refiner long 1,000 futures at 63.00 buys 1 m bbl from a producer via EFP at front-month 62.00 + 0.10 = 62.10, handing its futures to the producer:

  • Refiner: physical 62.10 + futures loss 1.00 = 63.10
  • Producer: sells at 62.10 and holds long futures to close when it chooses

6.8 US crude markets​

  • WTI delivered at Cushing; pipeline nominations by the 25th of the prior month (so 26 March–25 April prices reflect May delivery). Other US grades: WTS (Midland), LLS (St James), Mars (Clovelly), ANS (Long Beach).
  • CME WTI futures: 1,000 bbl, physical at Cushing, expire 3 business days before the 25th of the prior month; also RBOB gasoline and ULSD (42,000 gal, NY Harbor). RBOB is a blendstock — like base metals’ intermediate-stage contracts.

Pricing physical WTI: CMA + roll​

Price = calendar-month average (CMA) of front-month futures in the delivery month + NYMEX roll

Roll, computed daily over the prior trading month and averaged:

((M1 − M2) × ⅔) + ((M1 − M3) × ⅓)

Example day: May 40.28, June 40.58, July 40.87 → (−0.30 × ⅔) + (−0.59 × ⅓) = −0.20 − 0.20 = −0.40.

Correction

The source’s formula uses (M1 − M3) for the second term but its arithmetic uses (M2 − M3), giving −0.30. Applying the stated formula gives −0.40.

If the May CMA is 41.00 and the averaged roll −0.50, the producer receives 40.50/bbl.

Negative WTI: 20 April 2020​

COVID-19 crushed demand; Cushing was ~79% full (≈ 60 m of ~76 m bbl working capacity) with much remaining space already booked. Holders of the expiring May contract (≈ 13,000 lots open) faced taking delivery with nowhere to put the oil. The contract opened at USD 17.73, hit −40.32, and settled −37.63 — a USD 58.05 range — then expired next day at USD 10.01. Brent stayed positive. Index rolls added selling pressure. (Lesson 2: why Bachelier-type models were adopted.)

Checkpoint 3: Brent and WTI​

Quiz

Checkpoint — sections 6.7 and 6.8

1 / 5

Third-month forward 82.40; CFD for a future week −0.85. Implied forward Dated Brent?

Pick an answer to see if you are right.

6.9 Hedging along the supply chain​

ParticipantExposures
ProducerFlat price (falling), quality differentials
RefinerCrude cost, financing, freight, insurance, storage, crack spread
ConsumerProduct price, location differential, lack of a liquid hedge → proxy hedges

Producers​

Basis risk arises from: hedging one product with another, timing mismatches, early termination, different delivery locations, quality differences.

Futures strip with basis​

A producer sells 50,000 bbl a month (Jan–Mar), each priced at Platts WTI on the first business day; it sells Feb/Mar/Apr futures on 1 December and buys them back on each pricing day.

DeliveryCash priceFutures sold → boughtFutures P&LEffective price
Jan67.9369.67 → 69.32+0.3568.28
Feb67.5570.04 → 69.29+0.7568.30
Mar68.7970.63 → 71.15−0.5268.27

Average effective 68.28 vs unhedged average 68.09. Basis = cash − futures; effective price = original futures price + basis at close-out (e.g. 69.67 − 1.39 = 68.28). The producer swaps volatile price risk for smaller basis risk.

Multi-day pricing​

Selling 300,000 bbl priced on the average front-month close over 3 loading days (62.00, 63.50, 61.25 → avg 62.25): short 300 futures at 59.37, buy back 100 each day → futures loss 263,000 + 413,000 + 188,000 = 864,000; physical 18,675,000 → net 17,811,000 = 59.37/bbl exactly. (Perfect only because the physical references the same future and closes at the same prices.)

Swaps​

A producer with a fixed sales contract who wants floating exposure pays fixed USD 50, receives the monthly average futures price. Average 49.50 on 70,000 bbl → pays USD 35,000 — net, it sells at floating.

Common swaps: Brent and WTI futures averages; Dated Brent, Dubai, Tapis (PRA averages); gasoline Eurobob barges, RBOB, ICE gas oil, ULSD, gas oil and fuel oil barges/cargoes. Variants: fixed vs futures, index vs index (e.g. Urals vs Dated Brent), index vs futures, crude vs products.

Two-asset barrier: cheaper FX hedge​

A non-US producer receiving USD buys a 1-month EUR call / USD put on EUR 50 m, strike 1.1524: premium USD 0.0106 per EUR = USD 530,000 (= EUR 460,870 at spot 1.15, ≈ 0.92%).

Make it knock out if Brent trades above a barrier (when the producer is cash-rich anyway) → cheaper. Premium depends on EUR–oil correlation: −1 → 0.0106 (never knocks out), 0 → 0.0101, +1 → 0.0080. Closer barriers and continuous monitoring cut the premium; one-month range ≈ 20% / √12 ≈ 5.8% of the oil price.

Refiners​

FX-reset swap: a EUR refiner pays fixed USD 60 (vs crude at 70) for two years — but if EUR/USD ever trades above 1.25, the fixed price resets to USD 85. The subsidy is paid for with an embedded digital, American-barrier, cross-asset option.

3-2-1 futures crack: to protect margin, sell the crack = buy 3 crude futures, sell 2 gasoline + 1 heating oil (often later-dated products). Basis risks: location (Cushing/NY Harbor vs Gulf Coast) and quality.

Refinery margin swap​

Margin = 0.03 × naphtha + 0.41 × gasoline + 0.35 × gas oil + 0.21 × fuel oil − Dated Brent (products converted to USD/bbl). Refiner receives fixed 7.24 on 160,000 bbl/month for Q4:

MonthActual marginPhysicalSwap
Oct6.821,091,200+67,200
Nov6.03964,800+193,600
Dec8.111,297,600−139,200

Total 3,475,200 / 480,000 bbl = 7.24/bbl.

Options: buy a put (or sell a call) on the margin; a refining margin option is a basket spread option tailored to the refinery’s slate.

Calendar spread options and storage​

Calendar spread = near − far (negative in contango). Owning storage ≈ a put on the spread: in contango you store and sell later.

Example: gas oil Jan 903, Jun 889 (backwardated, spread +14). A storage owner sells a put on Jan − Jun, strike −10, premium 0.50; storage costs 7.

ScenarioJanJunSpreadOption payoutStore & sell?Total
1860890−30−20Yes (+30 − 7)3.50
2860868−80Yes (+8 − 7)1.50
3860866−60No (6 < 7)0.50
4860850+100No0.50

Consumers (airlines)​

Jet fuel swap: airline pays fixed USD 650/t, receives the monthly average Platts Jet CIF NWE, 10,000 t/month → net fixed 650.

Jet diff: jet = gas oil + jet differential. Gas oil USD 72/bbl × 7.45 = 536.40/t; jet 586.40 → diff 50.

Gas oil futures + jet diff swap: buy gas oil futures at 536.40 and a jet diff swap at 45 → locked 581.40. At maturity gas oil 550, diff 40 → jet 590; futures +13.60, swap −5 → 590 + 5 − 13.60 = 581.40.

Typical airline layering: long-dated crude (3–4 years) → gas oil (~2 years) → jet swaps (~1 year) → location-specific hedges (~6 months).

Regression hedge ratio (bank hedging a jet swap with crude futures)​

Δjet = α + β Δcrude + ε. With β = 0.8, hedge 1,000 t of jet (× 7.45 = 7,450 bbl) with 1,000 bbl crude futures:

Contracts = 0.8 × 7,450 / 1,000 = 5.96 ≈ 6. A USD 1 crude move → futures 6,000 vs jet exposure 5,960.

Questions: which jet index, sample length and frequency, timing, maturity, and conversion factor? Stack (one maturity, rolled — liquid) vs strip (matching maturities — may be illiquid)? β drifts, so rebalance; the bank may widen the swap price for imperfect hedging.

Compound options for uncertain volume​

For base consumption buy a strip of calls; for uncertain extra volume, buy a call on a call: pay USD 10 now for the right to buy, in one month, a one-month call (strike 600) for USD 21. If vol rises so the call would cost 24, exercise — but the total paid (31) exceeds 24: flexibility has a price.

Checkpoint 4: hedging​

Quiz

Checkpoint — section 6.9

1 / 6

Producer sold futures at 75.20; basis at close-out is −1.10. Effective sale price?

Pick an answer to see if you are right.

Rank: crude oil practice​

Quiz

Crude oil practice

1 / 2

Rank these Brent instruments from NEAREST to FURTHEST typical delivery timing.

OrderDrag the handle to rearrange — top should be first.

  1. 1Dated Brent (10 days–1 month)
  2. 2CFD weeks (out to 8 weeks)
  3. 3ICE Brent futures (out to ~8 years)
  4. 4Brent forwards (future months)

Drag items into the correct order (or use ↑↓), then check.

Check: crude oil​

Quiz

Crude oil

1 / 6

Demand for crude oil is best described as…

Pick an answer to see if you are right.

Calculate: numeric practice​

Type the number (no units; minus sign for payments or losses). 42 gal per bbl.

Formula sheet​

ItemFormula
Product revenue per bbl crudeprice (USD/t) ÷ bbl-per-t factor × yield
3-2-1 crack⅔ × gasoline × 42 + ⅓ × heating oil × 42 − crude
Implied forward Dated BrentCFD + third-month forward
EFP effective cost (long futures)EFP physical price + (original futures − close futures)
NYMEX roll (daily)(M1 − M2) × ⅔ + (M1 − M3) × ⅓
Effective hedged priceoriginal futures + basis at close
Regression hedge (contracts)β × exposure bbl ÷ contract size
Margin swap (fixed receiver)(fixed − actual) × bbl
Compute

Calculate: crude oil

1 / 12

Story problem — figure out which numbers are the formula inputs, then compute.

Gasoline USD 600/t, factor 8.35 bbl/t, yield 40%. Revenue per barrel of crude from gasoline (2 dp)?

Enter a number (at most 2 decimal places).

Randomized practice​

Compute

Practice: crude oil drills

1 / 6

Story problem — figure out which numbers are the formula inputs, then compute.

A producer sold futures at 79.38; basis (cash − futures) at close-out is -0.49. Effective sale price? Round to 2 decimals.

Enter a number (at most 2 decimal places).

Takeaways​

Remember
  • Crude is valued by its refined products: API, sulfur, acidity, flow decide the slate
  • Refiners maximise gross product worth − crude cost; crack spreads measure margins
  • Reserves and R/P ratios move with price and technology; reserves, production, and consumption are geographically mismatched
  • Drivers span macro, supply chain, geopolitics, OPEC/OPEC+; the short end is physical, the long end financial
  • Benchmarks: WTI (Cushing), Brent (BFOET basket, plus WTI Midland), Dubai/Oman; most crudes price as differentials
  • Brent complex: Dated (physical), forwards (paper), CFDs (Dated vs forward), futures, EFPs
  • WTI physical = CMA + roll; April 2020 proved prices can go negative
  • Hedges: producers (futures + basis, swaps), refiners (cracks, margin swaps, calendar spread options), consumers (jet swaps, jet diff, regression proxies, compound options)

Further Reading​