Chapter 2: Crude oil

Having set the framework for the discussion of energy commodities, it is now time to turn to the commodities themselves and concentrate on their physical and economic characteristics, their trade patterns, and the distinctive procedures for their exchange and pricing. Oil is the most important – and most written about – commodity, having provided energy for a host of human activities, from kerosene lamps, to motor cars and electricity generation. Fuel wood and wind were the main inanimate sources of power, until the discovery of steam power, which led to the use of coal for a vast number of applications. From heating, to steam locomotives, to textile factories, and steamships, coal was the cornerstone of European and American industrialisation, which started from Great Britain. It was oil, however, which caught the imagination of consumers, dethroned ‘King Coal’, and sent shock waves to the entire world with three massive price crises in the 1970s and 1980s, deflated prices in the 1990s, a meteoric rise in the 2000s, a collapse immediately after the 2008 financial crisis, a resurgence and persistence around the $100-per-barrel mark in the first half of the 2010s and continued fluctuation between $30-80 in the second half of the decade. And to top it all, the Covid-19 pandemic resulted in a reduction in oil production and demand sharper than that of the global financial crisis in 2008-9. We will first go on a brief tour of the history of oil and how the oil industry is organised, before discussing the physical characteristics of the commodity, how it is produced, who the main suppliers are, where is it consumed and how it is priced and traded. The refining end of the business is also very important, as it is refined products that are desired by the final consumers. However, we will take a closer look at refining in the next chapter.

A brief history

The history of oil is perhaps the most fascinating segment of modern industrial and commercial history. The oil sector is a relatively young industrial sector, just over a hundred and fifty years old. Oil is known to humanity since antiquity, but it was never used extensively, and then only for lighting. The little oil that was used, was collected from oil seepages, since no one systematically explored for, or extracted, oil.

The birth of the oil industry in the USA is credited to Edwin L. Drake, also known as the “Colonel”, although he was never actually a military man. After a long, expensive and desperate search, he eventually struck oil on the 27th of August 1859, in Titusville, Pennsylvania. The new fuel was thick, murky and difficult to burn. It had already been demonstrated by a Yale professor,[1] however, that it could be boiled and refined into several products that were adequate for industrial consumption. Refined to kerosene, the rock oil of Pennsylvania soon found its way to the market where it was used in lamps. The new discovery quickly captured the imagination. People flocked to the Oil Creek area in their thousands in pursuit of oil. Akin to a gold rush, fortunes were made and lost in a matter of months. The slightest suspicion of oil existence in an area, would send land prices sky-high. New towns were built in a matter of weeks, and were deserted as quickly, when local wells dried up and news of fresh discoveries reached the drillers. There were few rules regarding ownership of reserves and rate of production. The ownership of any underground resources remained with the owner of the land above it. Anyone that managed to acquire a piece of land, drill a well and strike oil, would start pumping it out as fast as possible, before his neighbour could do the same. Abundant discoveries and uncontrolled production soon brought oil prices down, however.

“Production in western Pennsylvania rose rapidly – from about 450,000 barrels in 1860 to 3 million barrels in 1862. The market could not develop quickly enough to match the swelling volume of oil. Prices, which had been $10 a barrel in January 1861, fell to 50 cents by June and, by the end of 1861, were down to 10 cents. But those cheap prices gave Pennsylvania oil a quick and decisive victory in the marketplace, swiftly capturing consumers and driving out coal-oils and other illuminants.”[2] 

Standard Oil

The lack of organised systems in the new industry, from production to final consumption was scorned by John D. Rockefeller, who set out to implement his strategy – “Our Plan”, as he called it – of ‘tidying up’ the oil business through unification and control. He understood early on that the new fuel was useless unless it was refined and then properly marketed. His plan, therefore, was to acquire and control as many oil refineries as possible. This was done very discreetly, often through representatives, and some of his shrewdest competitors joined the board of Standard Oil after being bought out. The name of the company itself was part of his strategy. Until then, oil products – essentially kerosene – were coming from all sorts of different suppliers, with great variations in quality, often with the intent to cheat customers. Standard Oil established reliability for its products and created brand loyalty. At the same time, Rockefeller built a massive organisation which controlled over three quarters of the US oil industry, although, through the Standard Oil Trust, its true extend was difficult to observe.

Standard Oil expanded its operations across the Atlantic and into Europe. The resistance it found there was much stronger than at home, as will be discussed in the next section. In the US, the company staved off criticisms concerning its corporate power. From the turn of the century, American public opinion started turning against Standard Oil, helped by Ida Tarbell’s revelations regarding the company’s predatory methods, and the eagerness of the Roosevelt administration to control corporate power. In November 1906, the US Government brought a suit against Standard Oil, charging it under the Sherman Antitrust Act of 1890 with conspiring to restrain trade. The lawsuit became a battle for the survival of the company. In 1909, the Federal court found in favour of the government and ordered the dissolution of Standard Oil.

“But how exactly was this vast, interconnected empire to be broken up? The scale was simply enormous. The company transported more than four-fifths of all oil produced in Pennsylvania, Ohio, and Indiana. It refined more that three-fourths of all United States crude oil; it owned more than half of all tank cars; it marketed more than four-fifths of all kerosene exported; it sold to the railroads more than nine-tenths of all their lubricating oils. It also sold a vast array of by-products – including 300 million candles of seven hundred different types. It even deployed its own navy – seventy-eight steamers and nineteen sailing vessels. How was all this to be dismembered?”[3]

Eventually, Standard Oil was broken up into several companies, each with a different degree of vertical integration in oil. The biggest was Standard Oil of New Jersey, which eventually became Exxon; Standard Oil of New York became Mobil and then merged with Exxon to become modern day ExxonMobil; Standard Oil (California), or Socal for short, eventually became Chevron; Standard Oil of Ohio became Sohio and was later taken over by BP; Standard Oil of Indiana became Amoco and was later also taken over by BP; Continental Oil is now ConocoPhillips; and Atlantic became part of ARCO, which was taken over by BP and has recently been sold to Tesoro, a downstream refiner.

The Europeans

The development of the oil industry in Europe was quite different from that in the United States. At the time, Western Europe did not have any oil reserves of its own. Coal was abundant in Britain and had captured the entire energy market. Due to lack of domestic reserves, European oil companies had to venture abroad from the very beginning. Oil had been discovered in Russia before 1800, in Baku, and it was soon developed with European capital; the Rothschilds and the Nobels were the most prominent investors in Russian oil.

The search for oil also led European companies to the Far East, where oil was discovered on the islands of Borneo and Sumatra. In this race to secure crude oil supplies and capture markets, two companies emerged as the strongest contenders: Shell and Royal Dutch. The former was founded and run by Marcus Samuel. His company was originally set up to control the transportation and retail trading of the commodity; in fact the full name of the company was ‘Shell Transport and Trading’.  Royal Dutch was smaller enterprise, which often struggled for survival. In December 1900 Henri Deterding was appointed ‘interim manager’ after his boss suffered a heart attack. He went on to lead Royal Dutch for three decades, making it into a leading international oil company. He avoided being taken over by Standard Oil, which was monitoring Royal Dutch’s rise very closely, and eventually succeeded in merging his company with Shell, on his own terms and conditions. Royal Dutch Shell was the most prominent European oil company, but not the only one. Burmah Oil had been set up to exploit oil deposits discovered in Burma; and a new company, Anglo-Persian, was founded to take advantage of what promised to be substantial oil reserves under the barren desert of southern Persia. Anglo-Persian was the culmination of the efforts of William Knox D’Arcy to find oil in the area. The company was officially set up in 1909 and its main shareholder was Burmah Oil. The operations did not run as smoothly as it had been hoped. Anglo-Persian was far from an integrated oil company. It was a crude oil producer, and it had to strike a deal with Royal Dutch Shell to gain access to consumption markets. It was a political decision, however, that turned Anglo-Persian’s fortunes around. Increasing friction between Germany and Britain created a need to develop a swift and powerful British Navy. Coal powered warships were difficult to manoeuvre; oil, on the other hand, offered increased manoeuvrability, but as a fuel it was also riskier to acquire and control. The enthusiastic First Lord of the Admiralty, Winston Churchill, believed in the merits of using oil and succeeded in convincing the British Parliament to switch the entire Royal Navy to the new fuel. Churchill also believed that the government should have closer control over energy resources for defence purposes. After looking at both Royal Dutch Shell and Anglo-Persian, the British government decided to choose the latter – to Samuel’s and Deterding’s intense discomfort and protest – and strengthened the company by acquiring a majority stake in it. It was the first demonstration of direct political involvement in the oil industry, and only the beginning of a history of political struggle to gain access to, and control over, this valuable commodity.

The Great War

All the efforts put into technological developments during the late 19th and 20th centuries, were deployed during the First World War. Although the war was initially planned on the use of men and horses, it was the use of the oil-powered internal combustion engine that made the crucial difference. Oil-powered aeroplanes and warships were used extensively, and vindicated Churchill’s foresight to switch to oil. The end of the Great War also signalled the break-up of the Ottoman Empire and the Allies jostled to gain a share of the remains. Key were the potentially oil-rich lands of modern Iraq and Saudi Arabia. The agreement took a few years to complete and included Anglo-Persian, Royal Dutch, Compagnie Française des Pétroles (CFP - the French state oil company), a consortium of American companies, and the architect of the deal, Calouste Gulbenkian. 

At the same time, interest in Middle Eastern oil by American companies was revived. Gulf – the oil company of the Mellon family – struck oil in Kuwait, together with Anglo-Persian. At the same time oil was found in Bahrain by Caltex, a joint venture between Socal and Texaco. With all the new discoveries, the world was definitely not short of crude, despite the surge in demand. Oil’s central role in the world economy would be amply demonstrated during the Second World War.

World War II

If oil revolutionized tactics during the First World War, it then dominated logistics of both sides during the Second World War. From beginning to end, the struggle was on for control over valuable oil reserves. Among the first places Hitler set his eyes on, when he started his Russian invasion, were the oilfields of Baku. From the south, Rommel had a similar target: to advance and capture the plentiful oil resources of the Middle East. On the Pacific front, Japan followed exactly the same strategy, and moved swiftly to capture the oil producing islands of the region. The Allies’ efforts were concentrated on stopping the Axis from gaining access to oil reserves, which they were controlling. The final stages of the Allies push towards Berlin are eloquently described by Daniel Yergin:

“Toward the end of August 1944, however, fuel was becoming a very serious constraint on the Allied advance. There was no physical shortage of gasoline in France. The supplies were simply in the wrong place – back in Normandy, far behind the lines – and there was an immense logistical problem in getting the fuel to the front. .... In consequence of their logistical problems, the fast-moving Allied armies simply outran their gasoline supplies. The same thing had happened to Rommel when his forces had raced across North Africa in 1942. Patton fumed about the situation. ‘At the present time’, he wrote to his son on August 28, ‘my chief difficulty is not the Germans but gasoline. If they would give me enough gas, I could go anywhere I want.’.... At that moment, Eisenhower, as overall commander of the Allied forces, faced a critical decision: whether to direct the bulk of available supplies to Patton’s Third Army or give the fuel to the United States First Army, to the north of the Third Army, in support of the British Twenty-first Army Group, under General Montgomery, which was closest to the coast. Was this the moment, Eisenhower had to ask himself, to forsake his own ‘broad front’ strategy – all flanks protected – and instead go for broke and let Patton and the Third Army try to punch through the Siegfried Line, the Nazi’s West Wall, into Germany itself?”[4]

In the end, Eisenhower chose his first alternative, to the utter frustration of Patton. His dilemmas on the battlefront though, would make him extremely conscious of matters relating to energy during his presidency of the United States.

Post-war growth

The massive reconstruction programme undertaken in Europe and Japan after the end of the Second World War would be impossible to sustain without a large influx of energy resources. In Europe, there was the obvious option to use coal. The coal industry was labour intensive and, hence, expensive. In Japan, on the other hand, the situation was more clear-cut: the country was simply devoid of any natural resources, save for some small coal reserves. 

The result of that large appetite for energy gave oil the perfect chance to penetrate – and, eventually, dominate – primary energy consumption. By the early 1960s oil had become the non-communist world’s largest single source of commercial energy (having attained the same position in the United States at the beginning of the 1950s), although fuel demand patterns varied considerably from country to country. In 1965 the degree of dependence on oil in the main importing countries ranged from 57 per cent in Japan to 39 per cent in the United Kingdom, where coal was to remain the dominant energy source until 1970. In the communist block, the USSR and China used predominantly coal throughout the 1950s and 60s. In the former, oil became the main contributor in 1974, but China remained – and still is – very much dependent on coal.

During the war, oil from the Middle East became increasingly popular as a cheap short-haul supplier, both to European and Japanese markets. Even the United States became increasingly reliant on the Middle East for its oil. As a result, the region became a prominent oil producer and an equally important exporter. American companies were keen to erase the status quo created by the Red Line and take advantage of the massive oil reserves in the Arabian Peninsula. In the meantime, those companies that were not part of the agreement had already made moves to strike concession agreements with individual Sheikhs. 

Oil had become the driving force of the world economy. Its abundance, however, meant that prices remained depressed throughout the 1960s. The desire of host governments to control and exploit their own resources, coupled with the unfair deal they seemed to be getting from the oil companies – reflected in the low oil revenues they received – led to the formation of an international body with the mandate to rectify the situation: OPEC. The organisation was faced with contempt, or even plain indifference, by the boards of most oil companies. After all, it could not achieve much more than clamouring for higher prices all the time.

The first oil price shock - 1973

The 1970s promised to be a decade of prosperity and unprecedented growth. From early on, however, the first indications appeared of an excessive dependence on imported crude oil, even in the US. In fact, the situation there was encouraging oil imports, particularly from the Middle East, in two ways: demand was growing rapidly; and domestic oil production was faltering dramatically simultaneously. It took the OPEC countries a few years before assuming their role as setters of world oil prices. In fact, the first rehearsal of what was going to ensue took place in Libya in the early 1970s. The nationalisation of Armand Hammer’s Occidental by the Qadaffi regime, and the ‘Tripoli Agreement’, took oil companies by surprise and raised the aspirations of host governments. It was the Yom Kippur war, however, that provided the excuse to oil producers to test their apparent favourable position. The Arab oil embargo – although abandoned soon after its imposition – also brought about two back-to-back increases in the price of crude, in October 1973 and January 1974. The world was taken by surprise, but there was not much they could do. Oil was the lifeblood of most economies and higher prices would just have to be accommodated. Despite the price shock, both oil production and exports continued unabated throughout the 1970s.

The second oil price shock - 1979

Throughout the 1970s, OPEC countries had maintained some kind of agreement with regard to production shares and oil prices. Agreements were quite cumbersome to conclude, since different countries had different plans about the use and remuneration of their oil resources. Countries like Iran were pushing for a larger share and higher oil prices. Conversely, Saudi Arabia was trying to moderate extreme demands by OPEC members. It was politics, once more, that provoked turmoil in the international oil industry. In 1979 the Iranian Revolution, led by the spiritual leader of many Iranian Islamic fundamentalists, Ayatollah Khomeini, dethroned the Shah and sent him in exile. Persia had caused trouble to western oil companies before. This time it was final. The new regime’s hostility towards any kind of western influence meant the dissolution of the oil companies and the repatriation of their staff. The new state of affairs shocked the world and sent oil prices to unprecedented heights. The price for a barrel of crude reached the region of $35. Many talked of an equilibrium price of $40 and a steady rise with inflation thereafter.

This time round, the reaction to the new crisis was markedly different from that in 1973. The first oil crisis proved right many advocates of the need for political security of oil and less dependence on it. The second oil crisis needed not only a political response, but an economic and technological response. Conservation programmes were introduced in many countries with the aim of discouraging the inefficient use of oil. One of the first victims of these policies in the US was the demise of the big cars of the 1950s onwards, which were beautiful to look at, but truly fuel inefficient: the famous gas-guzzlers. As a result, many American consumers turned to the much smaller, but also much more economical Japanese imports, which gave a huge boost to the Japanese car industry and made it one of the biggest in the world. Alongside the obvious demand destruction, high oil prices instigated oil exploration and production in politically safe areas – like Alaska and the North Sea – and made other sources of energy competitive again. 

The net effect of those developments was the notable reduction of the share of oil in world primary energy consumption (PEC), as can be seen in Exhibit 2, combined with an overall reduction in PEC between 1980 and 1983 (Exhibit 3), before it started rising again from 1984 onwards. The second, more acute, effect was the immediate reduction of oil consumed internationally and also oil imported from the Middle East. In 1980 alone, oil demand fell by more than 2.5 mbpd. The pattern would be repeated throughout the mid-1980s, and it took until 1988, almost ten years, to restore oil consumption to its 1979 level.

The reverse oil price shock - 1986

Within the span of just one decade the oil industry experienced two immense shocks whose effects rippled around the globe. With the price of oil skyrocketing after the second oil crisis, oil consumers had to reduce their total primary energy demand, and at the same time move away from oil and into other sources of energy. In the meantime, OPEC members welcomed the new windfall of increased revenues, but failed to recognise the deep structural changes in the world economy. Most of them were absorbed in their own plans of economic development, drafted on the back of strong oil revenues. When demand fell sharply, many OPEC countries felt threatened and struggled to gain market share, in order to keep their oil revenue intact. That, of course, meant anarchy within OPEC, as no country could be persuaded to curtail production to a pre-specified quota that would keep prices stable.

The first country to oppose any quota recommendation by OPEC was Nigeria. Its crude was very similar to that produced by the UK in the North Sea, and both countries were competing in the same market: the United States. Nigeria offered its crude at a discount of OPEC’s official selling price, in a desperate attempt to retain its share of the American market. Other OPEC countries followed suit, as a high oil price was worthless without any sales! The country that refused to be dragged into the vortex was Saudi Arabia, who continued to play the role of the swing producer, lowering its production in order to accommodate quota violations by other members. In the end, even Saudi Arabia gave in, and started quoting netback prices to refineries importing its crude. That sent the market down a chute, with the price of oil hitting a low of just below $10/barrel. The price collapse caused a shock, not only for OPEC members, but also for non-OPEC oil producers. Amongst the hardest hit was the UK, which saw a very profitable business being threatened overnight. Both OPEC and non-OPEC producers recognised the need for restraint in order to re-establish market equilibrium. Analysts started arguing about the need for the price of oil to remain at levels manageable for both producers and consumers. Many people started quoting $18-20/barrel as the ‘natural’ price of oil, which would make production in high-cost areas viable and would also provide some economic scope for further research in alternative sources of energy.

After the debacle of 1986, OPEC members had to resort to production allocation (quota) cuts in order to arrest the fall of oil prices. For the rest of the 1980s oil prices fluctuated around $15-20/barrel in nominal terms. Throughout the 1990s, the price of oil remained almost uninterruptedly stable, with the exception of panic buying just after Iraq’s invasion of Kuwait in August 1990 and before the successful military interference of western countries in January 1991. Once more, it was profoundly demonstrated how security of supplies was, and would continue to be, a major issue in the dynamics of the international oil industry. In the case of Iraq, confidence in the security of supplies was restored when Saudi Arabia stepped in as swing producer, in order to make up the loss of the Kuwaiti oil output. The world economy experienced another major shock in the form of the Asian financial crisis, which started in the second half of 1997. The crisis brought with it devaluation of a number of currencies in the region, collapse of highly inflated asset prices, withdrawal of credit by panicking lenders, bankruptcies and the resulting lack of confidence by consumers, producers and investors. The repercussion of a seemingly regional problem rippled through the world economy and did affect energy demand and demand for oil in particular. At the early stages of what became the crisis, OPEC members went to their November 1997 meeting in Jakarta with great optimism given by the growth of the Asian tiger and the great promise of the Chinese economy. Persuaded by Saudi Arabia, they decided to raise their production quotas from 25 to 27.5 mbpd (a 10% increase) and this decision could not have come at a worst time. What followed was another collapse of the oil price, which dwindled to an anaemic $10/barrel on average throughout 1998, before starting to rise again from the second quarter of 1999 and end the year at an average of $25.

The new millennium

The new millennium brought with it a new dawn in the world economy, the rapid ascent of several emerging economies and even a new term, BRIC, used to summarise the four most promising of these developing economies - Brazil, Russia, India and China. The modest recovery of oil prices at the end of 1999 did not give any hints as to the spectacular way in which they would keep rising, particularly from 2003 onwards. From a ‘reasonably firm’ $28/barrel, prices moved to over $40 in 2004, continuing unabated to $55 the following year and closing 2006 with several occasions when they surpassed the psychological barrier of $70. That price would not be a barrier in 2007, when the annual average price for Brent crude oil was above $70 and towards the end of the year it was already above $90.

The events of 2008 not only affected the oil markets, but the world economy as a whole. During the year, oil prices kept rising, as exuberance regarding the current and future growth of emerging economies took over the markets. The oil price hit an historical $147 in the summer of 2008, but soon afterwards the collapse of Lehman Brothers set off a chain reaction leading to the collapse of the world financial system, increased uncertainty about the state of health of financial institutions, strong pessimism about the fate of the world economy and future growth and an immediate slump in economic activity. Oil prices are frequently thought of as the barometer of the world economy and this was demonstrated in the strongest possible way. Oil prices collapsed from the meteoric highs of the summer months to a measly $35/barrel, ending the year with an average of just over $40 for the month of December 2008.

The effects of the financial crisis were felt almost immediately in the last quarter of 2008 and throughout 2009. Oil production fell, albeit marginally from 86 to 85 mbpd, and so did oil trade. In the end, the demand destruction that was feared was narrowly missed. The world’s appetite for oil continues: in 2019 we consumed almost 100 million bpd, but in 2020 demand dropped by 9 million bpd to 91 mbpd in the aftermath of Covid-19. This growth, however, is structurally different to that in the twentieth century. According to BP[6], oil consumption is forecast to flatline until 2035 and decline to 97 million bpd and this is in the BAU scenario. In its Rapid Transition and Net Zero scenarios, BP forecasts that oil consumption will drop to 47 and 24 million bpd, respectively, quite a stark outlook! Consumption in developed economies (OECD) is expected to fall in tandem, while consumption in emerging economies is forecast to to fall at a slower pace, as population and changing consumer tastes exert more pressure.

Concluding this section, the history of oil has been characterised by rapid expansion, and dramatic up- and downswings. This pattern has continued in the new millennium and challenges still abound. Demand growth in emerging economies, the aftermath of the Arab Spring, shale oil, the continued supply disruptions in various producing countries, Arctic oil exploration, the embargo on Iranian oil exports, carbon and other GHG emissions from production, refining and use of oil and its products are but a few of the issues facing the oil industry at the time of writing. The only certainty in the oil industry is that it will continue to fascinate and surprise for years to come.  Now, though, it is time to take a brief look at how this industry is organised.

Industry organisation

The oil industry is divided into three principal tiers, which cover all the stages from exploration to final consumption. The first tier is called upstream or E&P and deals with oil exploration, drilling and crude oil production. The second tier is called midstream and is concerned with the trading and transportation of the crude, which involves collection of crude oil cargoes from the production site and delivery to the final recipient’s destination, which could be a storage depot or a refinery. Finally, the third tier – downstream – deals with the refining of crude, and the marketing and distribution of oil products. Related to the downstream tier is the petrochemicals sector, which uses high-end petroleum products for the production of plastics, organic chemicals, pharmaceuticals, fertilisers and fibres.

There is a host of different parties involved in the various sectors of the oil industry. Big oil companies – or ‘oil majors’ as they are most commonly known – came into existence very early in the history of the industry, and are involved in all three tiers of production, transportation and refining. Until the 1970s, the history of the industry was, to a great extent, the history of the oil majors. Despite the predominance of those corporations, however, independent producers, refiners and traders always remained active. Most of these companies survive to date, albeit having gone through mergers, or having acquired other smaller oil producers to consolidate their position. Companies such as ExxonMobil, Shell, BP, Chevron, Total and Lukoil are some of the best-known ones on this list. They are now collectively known as IOCs (International Oil Companies), although the old collective ‘oil majors’ is still used extensively.

At the other end of the ownership spectrum stand the state trading corporations of oil producing nations, collectively known as NOCs (National Oil Companies). They came to prominence at the beginning of the 1970s, when oil-producing nations flexed their muscle and succeeded in gaining far better remuneration for their natural resources. Since then, their decisions about production and prices caught the immediate attention of the media, governments, producers and consumers, worldwide. They top the list of the world’s largest reserve holders, far exceeding the booked reserves of IOCs and among them they control probably 80% of world oil reserves. They are ‘oil majors’ in their own right, although their names are mostly known within their national boundaries and the oil industry, but are not household names per se. Such companies include Saudi Aramco, Venezuela’s PdVSA, Iran’s NIOC, Iraq’s NOC, Mexico’s PEMEX, UAE’s ADNOC and ENOC, Kuwait’s KPC, Nigeria’s NNPC, Angola’s Sonangol, Algeria’s Sonatrach, Russia’s Rosneft and Gazprom, Kazakhstan’s KazMunayGas, Azerbaijan’s SOCAR and several more. Being state-owned corporations, they were initially set up as political instruments to ensure continuous production and income generation, which can then be used in government policies. This role included, for example, the collusion to control production and dictate prices, as was the case with the member NOCs of the Organisation of Petroleum Exporting Countries (OPEC). In more recent years, the role of these companies is evolving, as they try to balance the political demands of their governments with the need to be commercially competitive.[7]

Somewhere between shareholder-owned IOCs and fully state-owned NOCs, the space is filled by corporatised national oil companies. The state still owns a big part of them, but they are also listed on one or more stock exchanges, they have strategic and operational autonomy and function fully as corporate entities. Companies such as Brazil’s Petrobras, Italy’s ENI and Norway’s Equinor (former Statoil) are typical examples.

The examples given above refer to companies spanning all three tiers of the industry, or at least upstream and downstream. There is a host of companies that specialise at either end, i.e. E&P or refining. Several oil (and gas) exploration companies operate around the world, both in well-established and frontier exploration areas, such as deep offshore or the arctic regions. Examples include Anadarko, BG Group, Cairn Energy, Dana Petroleum, Hess, Noble Energy, Perenco and several more. Joining that list are ConocoPhillips and Marathon Oil, who used to be integrated oil companies, often referred to as ‘mini-majors’. In 2012, both companies decided to split their upstream and downstream operations into separate entities. As a result, Phillips66 and Marathon Petroleum Corporation became the new refining entities out of ConocoPhillips and Marathon Oil, respectively.

There are also several downstream-only companies, concentrating on refining and distribution (via pipeline, trucks, tank railcars etc.) of petroleum products and petrochemicals. Examples include Valero, which holds the largest refining capacity in the US, Tesoro, Flint Hills Resources (part of Koch Industries), Phillips66 and Marathon Petroleum Corporation (mentioned above), as well as several smaller independent refiners, all of which buy their crude oil from the open market, domestic or international, and specialise in extracting the best possible value out of refining it and selling the finished products.

Since the mid-1970s and especially since the 1980s, when spot crude oil trade became more widespread, independent trading companies started being formed and gradually gained in importance. Following on from the pioneering (and rather notorious) Marc Rich & Co., independent commodity trading companies have become more widely known. Names such as Glencore, Vitol, Trafigura, Gunvor, Mercuria and several more are now quoted in the financial press and some of them even make it to the political dailies from time to time. Initially set up to take advantage of the few lucrative trading opportunities not pursued by international and national oil companies, commodity trading houses grew in terms of number and size of transactions, and geographical reach. More recently, they have also expanded their involvement in the supply chain of the specific commodities they deal with. They are not mere intermediaries only engaging in sale, purchase and transportation of cargoes, with perhaps cargo blending added as well. They may own storage facilities, they may have stakes in the upstream side of the business (for example oil and gas production licences, or stakes in mines if they also trade in mineral commodities), or the downstream side (with stakes in refineries or metal smelting) and they will generally try to extract value from all stages of the supply chain of the commodity.

In parallel to these companies, a number of financial institutions increased substantially their involvement in the business of trading oil derivative products, including forward, futures and option contracts, as well as physical crude oil and products. Their initial dominance in the oil derivatives (or paper) market was followed by increased activity in spot trading of the physical commodity, and even acquisition of storage facilities, shares in refineries and involvement in the transportation of the commodities. Financial houses such as Goldman Sachs (who acquired commodity trader J. Aron), Morgan Stanley, Barclays Capital, JP Morgan (until 2013, when it decided to start winding down some of its commodity activities), Macquarie and others came to be known as the ‘Wall Street refiners’.

Physical characteristics

Oil is one of a number of hydrocarbon compounds that can be found in the earth’s crust. In fact, four-fifths of the world’s sedimentary basins provide suitable geological conditions for the formation of crude oil. On several occasions, parts of the earth’s crust move against each other to form an anticline, which creates a reservoir of impervious rock, where organic material is trapped and broken down by enzymes over a period of several million years. A reservoir usually contains several oil fields, some of them grouped together in provinces. The organic material contained in the fields is a mixture of oil, water and gas. Oil floats on top of the water, while gas provides pressure in the field, which is invaluable for the extraction of the precious fuel.

What comes out of the oil well is a mixture of hydrocarbons and, hopefully, small quantities of nitrogen, oxygen and sulphur, as well as traces of iron, nickel, copper, vanadium and other elements. The hydrocarbons are usually a mix of various different types, broadly classified in paraffins, napthenes, aromatics and asphaltics. Paraffins can be a mixture of short chain molecules, such as methane, ethane, propane and butane, which are gaseous,[8] and longer chain modules, such as pentanes and above, which are heavier and occur as liquids. Napthenes typically include cycloalkanes, which consist of one or more carbon rings to which hydrogen atoms are attached. Aromatics are more complicated molecules with alternating single and double bonds between carbon atoms. A typical example is benzene, which is an important component of gasoline because of its high-octane number. Asphaltics are very heavy hydrocarbons, which occur as highly viscous liquids or solids, such as bitumen and asphalt.

Different geologic conditions affect the hydrocarbon formation in each and every reservoir. As a result, there is little standardisation in the composition of the various crude oils which are produced around the world. In fact, each oil needs to be analysed (or assayed) in a lab in order to determine its chemical composition. This assay typically includes characteristics such as density, specific gravity, viscosity and content of sulphur and other metals. These are all important physical characteristics, which have commercial importance. Of these physical characteristics, three are more widely known, especially when it comes to trading and pricing crude oil. The first one is specific gravity. Crude oils are classified as: light, or paraffinic; medium, or mixed-base; and heavy, or asphaltic. Light crudes have lower specific gravity and are easier to refine. Specific gravity is measured in ‘degrees API’, which were introduced by the American Petroleum Institute. 

One more detail: the centistoke value of a crude oil changes with temperature. Hence, a typical assay will contain viscosity measurements at several temperatures. For comparison, the kinematic viscosity of water at 20ºC is approximately 1. Finally, the third important characteristic of a crude’s quality is its content in sulphur. Crude oils with high sulphur content, above 0.6% by volume, are known as ‘sour’ crudes, while the rest are described as ‘sweet’.

Exploration and extraction

Oil exploration is the sector of the oil industry that has always caught the imagination of the masses, as it contains a huge element of risk, but offering the possibility of extremely good returns. Modern oil exploration does not rely that much on luck any longer. A number of scientific methods are used for the location of possible oil reservoirs and the estimation of their reserves. These are usually grouped in three main categories: geological analysis; geophysical surveys; and drilling and well logging.

Geological analysis includes a number of alternative – and often complementary – methods, ranging from traditional field geology (examining surface rocks), to the use of orbiting satellites. Geochemical analysis is also used, in order to establish the presence of suitable material for the formation of oil deposits. The aim of all the above techniques is to understand the geological structure and history of an area and decide whether it is worthwhile to spend more money on exploring it.

The main geophysical technique used for some time now is the seismic survey, although gravimetric and magnetic surveys can also be used to identify underlying structures that are possibly oil-bearing. Seismic surveys involve the artificial generation of shock waves, using a variety of techniques, like controlled explosions, dropping of weights and vibration generators. The aim is to record the reflections of those waves by the various geological strata. The data are recorded by geophones, which are similar to seismographs, and then transmitted and recorded. 

The recording stage is followed by the processing of the data collected, which involves their enhancement by computers. Finally, the results are interpreted by experts, who build an image of the underground formations and the likely location of deposits. All three stages (recording, processing and interpretation) have been immensely improved by the use of enhanced computer technology. The latter has allowed the advance from 2D to 3D seismic surveys, which use a lot more signal recorders and provide a far more accurate picture of underground formations. Initially, a traditional 2D seismic survey was shot along individual lines, at varying distances, producing ‘pictures’ of vertical sections of the underground formations. A 3D seismic survey, on the other hand, is shot in a closely spaced grid pattern and gives a complete, more accurate, picture of the subsurface.

The next stage in oil exploration is well drilling. To collect more accurate survey data, boreholes are drilled on top of the area suspected to contain oil reserves. Drilling is done by means of rotary drills, which create a borehole with the help of drilling mud. The mud is used to lubricate and cool the drill bit, contain the pressure, remove the cuttings and prevent the borehole from collapsing on itself. It typically consists of water, bentonite clay, barite and several chemical additives.

Many of these wildcat drills end up as dry holes. The purpose of the boreholes is not only to extract the oil. For the purposes of well (or mud) logging, rock cuttings, core samples and geophysical data are extracted from boreholes, giving scientists a more accurate picture of the local geological structure and, if any oil does exist, the history, nature and extent of the reservoir. Drilling itself can be quite challenging due to the location and the structure of the reservoir. When exploration is on land, the drilling platform can be assembled reasonably quickly and efficiently and occupies a relatively small space. When the reservoir is offshore, then a number of solutions exist, depending on water depth and weather conditions. One such solution is a fixed drilling platform, however this can be quite limiting as it cannot be moved easily and relies on the fact that the field is large enough that production will last for a few decades, so that the platform can be used to the end of its life. A fixed platform also presumes that a subsea pipeline system is in place, which will take the oil production from platform and transfer it on shore.

The boreholes that are successful eventually become oil wells. Neighbouring wells are normally grouped together to define an oil field. To date, there are over 30,000 known oil wells. Of these, 330 produce just over 50% of the world’s oil output, while just 17 of them produce over 30% of the same. Some of the wells are classified as giants – each holding over 0.5 billion barrels of reserves – while the biggest of wells and/or fields are also known as elephants. The largest of all oil fields, Ghawar, is located in Saudi Arabia, and is estimated to hold approximately 50 billion barrels of oil reserves. To put this in perspective, the Ghawar field accounts for about a sixth of Saudi reserves (estimated at 297 billion barrels in 2018).

The discovery of oil deposits and the drilling of oil producing wells is not, of course, the end of the story. The entire production process has to be organised properly. This involves a detailed reservoir management plan; the well layout and design; design of production and evacuation facilities; and an implementation schedule covering the drilling of wells and construction and installation of facilities, including oil treatment equipment to remove salt, water, sediment and other contaminants, local storage and transportation arrangements. The latter is typically a smaller, gathering pipeline that is connected to a larger, trunk pipeline, although transportation could mean the building of an offshore vessel terminal to load the oil onto tankers for export. In some case, transportation can be by mode of tank railcars, as is the case with some of the oil lifted from Canadian oil sands production sites.

The next step is to ensure that oil can be extracted in the most efficient way. The reservoir’s own pressure is usually sufficient to drive the oil or gas to the surface. In new oil fields, this pressure may last for years or even decades, when the oil recovery reaches a plateau. Ultimately, however, the removal of deposited oil will have a detrimental effect on the recovery level. When recovery levels are low, secondary recovery enhancements can be used, whereby the reservoir’s natural drive is supplemented with the injection of water or gas. Finally, where both natural drive and secondary recovery are not producing the desired production levels, tertiary or enhanced oil recovery (EOR) methods can be used. These techniques are considerably more expensive and must be justified by oil market conditions. 

Oil is not the only fuel produced by oil wells. Natural gas liquids (NGLs) are by-products of oil extraction. NGLs include: a type of light oil called natural gasoline; a mixture of petroleum – or ‘wet’ – gases, like butane, propane and ethane; and sometimes natural – or ‘dry’ – gas, which is methane.

In the last few years, there has been much discussion and excitement about considerable new sources of so-called non-conventional oil. Not all experts agree on a definition and, indeed, any available definitions do change with time and new discoveries. Some industry experts focus on the method and economics of extraction, others are more interested in the specific gravity and viscosity of these oil resources. The IEA classifies unconventional oil resources in a number of categories. These include: bitumen and extra heavy oil, with specific gravity of less than 10ºAPI, such as the Canadian oil sands; heavy and extra heavy oil, with specific gravity of less than 20ºAPI, such as the resources in the Venezuelan Orinoco basin; oil obtained from kerogen contained in oil shales, like the ones abundant in the United States and in the process of being extracted at the time of writing; and synthetic oil obtained by using the Fischer-Tropsch process either directly on natural gas (gas-to-liquids or GTL), or on synthetic gas obtained from coal (coal-to-liquids or CTL). 

All of these oil resources are far from inexpensive. However, since the early 2000s the industry showed renewed interest in developing them, initially oil sands in Canada and since the early 2010s oil shales in the US. As can be seen in Exhibit 5, oil sands remain quite expensive to develop, although their average cost is now below $100/bbl. What has become the great success story since 2010, however, is the intensive exploitation US shales and substantial production increase in tight (shale) oil, with a parallel drop of production costs in the range of $35-55/bbl. In 2000, the US produced about 8 mbpd with less than 10% of it classed as tight oil. In 2022, the EIA estimated that tight oil production alone was 8 mbpd, or two thirds of the total 12 mbpd produced in that year.

Reserves

As with any non-renewable natural resource, it is important to be able to establish the stock of reserves available for future extraction. But what are reserves and how are they different to resources? Exhibit 6 gives a good idea of how to proceed. Potential resources are those quantities of oil which are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations. Contingent resources are those quantities of oil estimated, as of a given date, to be potentially recoverable from known accumulations by application of development projects, but which are not currently considered to be commercially recoverable due to one or more contingencies, for example lack of access to the resource due to political issues. In contrast, reserves are those quantities of oil anticipated to be commercially recoverable from known accumulations from a given date forward under certain conditions, which are defined as follows. 

Oil ownership

When we talk about reserves and production of crude oil, we often do this with reference to the various countries where production takes place. However, it is is individual companies, whether national or international, which extract the oil and also have title to at least part of this production. So how does ownership of the reserves work? In the United States and Canada, the law grants the owner of the land the rights to any mineral reserves, including hydrocarbons of course, which are below the land. This rule has allowed intense oil prospecting, particularly in the United States, by private individuals and small entrepreneurs who may either produce their own oil or lease/sell their land to an oil company who can produce it on their behalf and pay them a proportion of the proceeds. Alternatively, oil companies can purchase and accumulate land, where they feel there are good chances of discovering economically recoverable oil and then proceed with production and sale of the crude oil found. The government still has the overall control over how the industry is allowed to develop and can indeed influence this through fiscal measures, such as tax incentives, import or export restrictions and so forth.

In the rest of the world, national laws typically grant the state title to all hydrocarbons and general mineral rights, both within the land mass of the country and, where relevant, offshore and within the country’s exclusive economic zone (EEZ). With this as the starting point, international oil companies (IOCs) can obtain title to a least a portion the hydrocarbon production with the help of the particular contracts that each country decides to offer, in order to develop and exploit its hydrocarbon resources. These agreements can vary in their detail, but typically fall into two categories: concessions, licences or royalty/tax systems; and production sharing contracts or agreements (PSCs or PSAs).

In countries such as the United States, Norway, United Kingdom, Australia and several others, the state invites IOCs to bid for concessions of licences, which grant the right to explore a specific area (known as a bloc) within a set period of time and produce the oil and/or gas contained therein, if indeed there is any. If exploration is unsuccessful, the IOC will have simply lost its licence fee and any investment that has gone in the oil exploration itself, all of which are sunk costs. If the exploration is successful and the company starts producing hydrocarbons, then the host government stands to earn additional income in the form of royalties and tax payments. A royalty is a percentage of the oil produced which the oil company who has bought the lease (the lessee) has to give to the government, which has granted the lease (the lessor). The royalty can be paid in kind, i.e. oil, if the government feels it has the right skills to sell this oil on its own to the international market, or simply needs the oil for domestic consumption. In practice, however, most governments prefer to collect the royalties in cash as a proportion of the value of production. For the IOCs, this means that they take title to the gross oil production at the wellhead, but they have to pay the royalty either in kind or in cash to the government. 

Once the royalty has been deducted, the IOC is allowed to recover costs or take tax deductions. There are two main cost components here: investments, or capital, costs and operating costs. Governments will typically offer investment allowances and tax credits or deductions, in order to allow the oil company to recover its costs. In many cases, both methods do this by simply assuming that costs are a percentage of the gross revenue from production.

Having deducted the royalty and recovered costs, what now remains is known as profit oil. At this point governments typically also require tax payments. Although the taxation principle may be quite straightforward, the details can vary considerably from country to country. For example, there may be a number of different layers of tax, as well as different tax rates. It is not uncommon for countries to impose a corporation tax on the companies’ profits, after deducting investment/capital expenditure allowances as described above, and then to also impose a special petroleum tax. In Norway, for example, the government charges a normal corporate tax of 28% and a special petroleum tax of 50%, so that the marginal tax rate is 78%. The way this works is as follows:[9]

From the mid-1960s onwards, an increasing number of governments, particularly in oil-rich developing nations, sought tighter control of their natural resources, in order to use the revenue from this resource to promote their own economic development programmes. This involved a large share of the oil production being taken over by the government, who then sold it to raise revenue for the country’s needs. In order to formalise the way in which oil production would be shared between IOCs and the government (or in many cases the national oil company acting as a government agency), a number of PSCs were used. The PSC is for the host country both a means of raising revenue as well as developing its expertise in exploration, production and commercial exploitation of its resources. To this effect, a PSC normally stipulates that the national oil company (NOC) has the option to participate in the commercialisation of a discovery, at the point that it is evident that the discovery has been made and there is oil to extract and sell. This option may or may not be exercised – but if it does then it provides the NOC with an excellent opportunity to increase its knowhow, technical ability and commercial awareness, particularly if the NOC is a novice in the industry. The systems used in a PSC to share the production and costs are not dissimilar to royalty/tax regimes, although the terminology may vary somewhat. Many PSCs now also include an element of royalty as a percentage of the gross oil production. Once this is deducted, the IOC is allowed to recover its costs, or what is known as cost oil. Often PSCs impose limits on how much of the cost can be recovered, so they make sure that not all oil becomes cost oil and they are left with nothing to share. Once the royalty and cost oil have been deducted, what is left is profit oil. It is this oil which is then shared between the government (or NOC) and the IOC. In addition to this, the government may also charge an additional income tax, although the way this is applied often varies from one country to the next and may burden the NOC, rather than the profit oil of the IOC.

A third way for an IOC to be involved in oil exploration with a host government is via a service contract or agreement. In this case, the IOC acts merely as a contractor, who is paid in cash and has no rights on the oil produced. There are cases, however, where the payment is in kind, so that the IOC is paid in oil or is given the right to purchase the oil from the host government at a preferential (lower than the market) price. Such service agreements, however, are rare between IOCs and governments, although the are commonplace between IOC and oil services firms, such as Schlumberger, Baker Hughes, Halliburton and so forth.

The continued growth of oil production, however, does come with a number of challenges: decreasing rate of oil reserve growth, which many simply call peak oil; location of lower cost reserves in politically challenging regions; resort to production of increasingly more ‘difficult’, and hence more costly, oil are just a few of these challenges. So which regions contributed to world oil production in 2023? Exhibit 11 shows the key oil producing regions. The Middle East is no surprise at all – the region holds ca. two thirds of the world’s oil reserves. Second comes North America, boosted by Canada’s oil sands and the continued activity of the United States in exploiting old marginal wells and bringing shale oil into production. CIS comes third, essentially Russia and Kazakhstan. Asia Pacific is next, with China producing half of the region’s output. Next comes Africa, with countries in the West, such as Nigeria and Angola, taking the lead, but also important suppliers in the North, such as Egypt and Algeria. Finally, South and Central America is led by Brazil, which yields about half the region's production, with the remaining countries making smaller contributions, as Venezuela's production has been hit in recent years by sanctions and internal political problems. In Exhibit 12 observe the relative contribution of the major oil-producing blocs, on the right-hand side, where the role of OPEC members can be clearly seen. If one adds OPEC and CIS, the message is that OPEC+ accounted for nearly 50% of global production in 2024. For a more detailed look of the top producing countries, Exhibits 13 and 14 offer the relevant information.

As is already evident, OPEC’s share of world production is pivotal. OPEC members continue to meet frequently during the year, in order to discuss the demand and supply situation in the international oil market. Unlike earlier days, however, nowadays they do not set prices. Instead, they focus on setting (or leave unchanged) production allocations among members: the famous OPEC quotas. Official announcements coming from OPEC meetings still seem to exert some influence, although various academics who have studied this question do not arrive at a comprehensive answer. Adelman (2002) has studied one of the longest time series of oil prices, from 1947 to 2000. He observes that OPEC exerted more power and had a bigger impact on oil prices during this period of price setting, particularly in the late 1970s and all the way up to the mid-1980s. For the period post-1986, he notes the political challenge of persuading members to agree quotas, in the face of international competition and while trying to retain their share of the oil export market. Several scholars have also attempted to determine the market power of OPEC, as well as the possible impact of quota decisions at OPEC meetings on world oil prices.[10]

We leave the reader with two more exhibits, which demonstrate the relationship between OPEC-related figures and oil prices. Exhibit 15 gathers data from the last two decades on OPEC official quotas plotted against actual OPEC production and world oil prices, using Brent crude as the benchmark. Although OPEC quotas are set, it is interesting to see that they are not always strictly adhered to and, in fact, actual production can vary considerably. The exhibit depicts crude oil production coming out of OPEC members, excluding natural gas petroleum liquids (NGPLs or NGLs). This level of production reflects the quota set by OPEC members and should be very close to it, but as is evident it does divert and runs at a higher level almost consistently. This is partly owed to the fact that Iraqi, Libyan and Venezuelan production are excluded[11].

Another interesting aspect of OPEC’s role in the market is shown in Exhibit 16. This is the relationship between estimated OPEC spare production capacity, plotted against world oil prices, using West Texas Intermediate (WTI) as the benchmark this time. Although we do not formally quantify the relationship of the two series, a quick graphical inspection shows how low levels of spare production capacity put a strain on oil prices. This relationship is evident during the period 2003-2008, when oil prices kept rising against a background of relatively low spare capacity, which ran between 1 and 2 mbpd, culminating in the oil price peaking in Q3 2008 while spare capacity remained at a measly 1 mbpd. This situation was reversed immediately after the 2008 financial crisis. By Q1 2009, spare capacity had tripled and oil prices had collapsed to an average of just over $40/bbl for that quarter. The same effect can be observed between Q2 2020 and Q2 2021, when spare capacity shot up to over 8 mbpd following the decline in oil demand due to Covid-19 and the decline of WTI, which averaged $31 in Q2 2020, having collapsed to an unprecedented -$37 for one day in April 2020.

Consumption

The world consumption of crude oil reached 101 mbpd in 2024, rebounding above 2019 levels, after falling by ca. 9 mbpd to 90 mbpd in 2020. Despite this, most forecasts expect consumption to remain flat and enter a declining path from 2030 until 2050. This is driven by the changing consumer tastes of emerging economies but moderated by much slower growth in developed economies and increased energy efficiency brought about by improved technology. Historically, the growth of oil consumption has continued unabated for nearly 50 years, with the notable exceptions of 1974-75, 1980-83, 2008-9 and 2020, i.e. the two oil price shocks, the world financial crisis and Covid-19. Although the rate of growth from 1984 onwards is notably less steep than that of 1965-1973, and the share of oil in world primary energy consumption has fallen to 34%, from a high of ca. 50% in 1973 (see Exhibit 17), oil remains the world’s biggest commodity, both in terms of its value and its volume. Despite continued talk of oil’s demise in the near future, there are several premium uses for it, which will find it very difficult to continue, unless an equally efficient technology is developed. Two sectors in particular rely on oil extensively: transportation and petrochemicals. The latter’s dependence is obvious – petrochemicals are derivatives of oil and require refined oil products (primarily naphtha but also petroleum gases), which are then processed into plastics, chemicals, organic fertilisers and a whole range of products consumed by other industries and final consumers. For transportation, oil has been the most efficient way to move a vehicle between two points, particularly cars, trucks and aeroplanes. It is true that there is a lot of research and development going into oil substitutes for transportation, including EVs, use of biofuels, hybrid cars and so forth. All, however, also have disadvantages and it will take some time until new technologies mature, work alongside existing oil-based technology and eventually take over.

With this as a background, let us now look at the world’s major oil consumers. While North America and the EU have historically been the main hubs of oil consumption, it is Asia Pacific, led by China, which now dominates this field. North America consumes a quarter of oil production, while Europe follows on with about a seventh, with the M. East consuming about a tenth. However, Asia Pacific dwarfs both of them, generating over a third of world oil demand. Exhibit 18 shows details for all major regions and their share of oil consumption.

On a country level, the United States continue to be the world’s foremost oil consumer, although their share of total consumption has fallen from over a third about fifty years ago, to around a quarter until the mid-2000s and eventually to just over a fifth in the last five years. China has experienced the most rapid growth in oil demand over the last twenty years. From 1991 to 2001, China’s consumption doubled from around 2.5 mbpd to 5 mbpd. In another ten years, from 2002 to 2012, it doubled again to just over 10 mbpd. In the last six years consumption rose by another 35% to reach 14 mbpd in 2020; China is now the world’s second largest consumer. It is necessary to put this into perspective with regard to the population of the two largest consumers – ca. 330 million for the US and ca. 1,380 million for China. This uncovers the big gap in per capita oil consumption in the two countries – 0.45 tonnes of oil per capita per year for China and 2.7 tonnes for the US, about six times as much.

Exhibit 19 shows the world’s twenty largest consumers of oil in 2024. In this list, of note is Japan, a country which is totally dependent on imports for its energy requirements. Since the first oil crisis, Japan has been striving to reduce its dependence on oil, firstly by increasing its oil efficiency (exemplified by its car technology) and secondly by moving away from heavy industry and into more knowledge-based industry, such as consumer electronics. Japan’s oil consumption peaked in 1996 at 5.8 mbpd and has been slowly but steadily declining since then, having shrunk to 3.2 mbpd in 2024.

In contrast, the second country in the table, India, has registered an impressive ascent to a leading oil consumer, overtaking South Korea in 2001 and eventually Japan in 2015, although it still remains a very low per capita consumer, given its population of ca. 1.4 billion. The increasing role of emerging economies in the last decade is also confirmed in Exhibit 20, which depicts how the balance of oil consumption has moved away from OECD, towards non-OECD countries and how both groups now consume about half of the world’s oil production.

Trade in crude oil

From a total of 101.4 mbpd of crude oil produced in 2024, some 42.7 mbpd were traded internationally, i.e. 42% of total production. Approximately 80-90% of these exports were carried by sea, with the balance carried by pipelines, especially between the United States and Canada and between Russia and the rest of Europe. Throughout oil’s turbulent history, international trade has played an important role. In fact, one of the biggest integrated oil companies – Royal Dutch Shell – started life as a trade and transport company. The fortunes of the tanker market have been driven by the economics and politics of the oil market. It makes sense, therefore, to understand the development and current situation of international trade in crude oil and its products.

A brief history of oil trade

Trade in oil was initiated from the early days of the industry, near the end of the 19th century. Before the First World War, international trade was almost exclusively in products. Carrying crude was quite uneconomical, due to its low value in comparison with its transport cost. Refineries were also located at the production sites, so that the final products only were shipped to the end-users. Most of the world trade in oil products was structured around the United States, which was the leading producer and exporter of oil. Standard Oil had a strong foothold in Europe and controlled most of the fleet carrying its oil from the United States. In Europe, in the meantime, Russian production became exportable with the completion of the trans-Caucasian railway. Subsequently, Russia dominated the markets of the Near East and a small share of the European market. The Bolshevik revolution in 1917 disrupted Russian output, but both production and exports were resumed in 1920.

At about the same time, crude oil started being traded internationally, even though it was carried on short-haul routes. The main crude oil exporters were Mexico and later Venezuela, with United States being the recipient. With the gradual expansion of Middle East and South-East Asian oil production, crude oil trade increased in importance; there was little scope for local refining, and the majority of refining capacity was now located in the consuming markets. 

From 1939 to 1945, world oil production and exports mirrored the energy needs of the Second World War. Oil for the Allied Forces was arriving from the United States with increasing difficulty, on account of the submarine attacks in the Atlantic. On the other hand, the Allies managed to secure control over the oil reserves of the Middle East, whose contribution in oil production increased substantially during the war. The military importance of the area was highlighted towards the end of the war, with the construction of the big oil refinery and terminal in Ras Tanura.

After the end of the Second World War, Europe had increased needs for energy resources in order to proceed with its reconstruction. A large part of those needs was covered by the Middle East, which became the world’s leading oil exporting region, especially after production of the large Kuwaiti fields came on stream. During the same period, the United States transformed into a net oil importer, with most of its imports coming from Venezuela, although some crude imports had already originated from the Middle East in the late 1940s. The old adversary of the US in the European market, the Soviet Union, resumed exports in the late 1940s, with most of them being directed to other countries in the Communist bloc.

Simultaneously, Japan also embarked on its post-war reconstruction programme. With energy resources virtually non-existent domestically, Japan had to resort to oil imports, in order to fuel its rapidly growing economy. In its quest to secure crude oil supplies, Japan turned initially to Indonesia (the former Netherlands East Indies), and even the Soviet Union. As the Middle East continued its rise to world domination of oil production, the Japanese eventually entered agreements with both Saudi Arabia and Kuwait, in the late 1950s. The Japanese involvement in the Middle East was very low profile from the beginning; even their exploration company was discreetly named ‘Arabian Oil Company’. Their venture in the Middle East provided the Japanese with an independent – i.e. non-oil major – source of oil, supplying about 15% of their needs.[13]

The major characteristic of this period (roughly between 1945 and 1960) was the substantial increase of international movements of oil, and the rising importance of the trade in crude oil. That period, however, was not devoid of turmoil. In 1956 the Suez Canal was closed, causing a major disruption in the trade and distribution of crude oil from the Middle East, and sending the tanker market sky-high overnight. Although the effects were not lasting, the whole incident amply demonstrated the role politics were going to play in the post-war order in the oil industry.

The 1960s was an era of growth: of oil trade, and crude oil in particular; of the export expansion of the Middle East; and of the size of tankers used to carry oil internationally. Western Europe, Japan and the United States experienced high levels of growth during the decade, with a resultant augmentation of their energy requirements. At the same time, refinery capacity and throughputs increased immensely in all the major importing regions. Within the span of ten years, world refining throughputs increased from 21 mbpd to almost 45 mbpd. Most were accounted for by West Europe and Japan. Within a decade, from 1960 to 1970, the volume of crude oil exports almost tripled, from just over 9 mbpd to just over 25 mbpd. In both cases, the Middle East accounted for about half of the world’s crude oil exports, half of which were directed to Western Europe.

At the same time, Venezuela also became a prominent crude oil supplier, with total exports in 1970 amounting to just under 3.5 mbpd, two-thirds of which were exported to the United States. The vision of Pérez Alfonso, the Venezuelan Minister of Mines and Hydrocarbons back in the late 1950s, could now become a reality: oil producing countries commanding higher economics rents for their natural resources; the economic fundamentals were in place at the end of the 1960s. The three first years of the 1970s, however, did not give any indication of the huge changes afoot. GDP growth rates were buoyant, industrial production and energy production had strong forecasts attached to them, and the future of crude oil trade looked better than ever. The rush of shipowners to order new tanker tonnage could only be compared to the oil rush of the 1860s in Pennsylvania; the anti-climax would be equally harsh.

While world economic growth had been providing the necessary impetus for an upward movement of oil prices, an increasing supply from old and new producers negated any demand squeeze. In fact, during the 1960s, prices had been rather slack and oil companies had repeatedly readjusted their posted prices downwards, much to the frustration of host governments, who saw their oil revenues being undercut.

Yet the beginning of the 1970s witnessed a demand rally, particularly in the United States, with a combined fall in domestic production and a surge in demand. As a result, crude oil import requirements had to be revised upwards and had to be covered mostly by the Middle East.

Despite the tight demand/supply balance, the oil price regime did not look particularly threatened. It was a political event once again – the Yom Kippur War, and the subsequent Arab oil embargo on exports to the US – that created a tremendous price rally and gave oil producers the chance to test their strength. The result was an approximately fivefold increase of the price of crude oil, which jumped from about $2/bbl to over $15/bbl, with some extreme cases of bids over $20.

The new developments took everyone by surprise, including oil producers themselves, but there was no question of curtailing oil consumption. Even the US embargo itself did not last for long. The blacklisted countries soon started procuring their crude oil requirements from other countries that imported from the Middle East. It was now evident that the new price levels were there to stay. The interruption of world economic growth, because of the first oil price shock, was quite short-lived. Economic growth resumed in 1974, although at lower levels; so did oil consumption and the demand for oil imports. In fact, during the 1970s dependence on the Middle East increased.

The Middle East, of course, was not the only OPEC producer. Venezuela had a substantial share of the American market, while Indonesia was an important oil supplier to the Japanese market. In the western world there were no substantial oil producers, or at least not large enough to substitute the Middle East as a prime source of oil imports. The USSR was a substantial producer and exporter, although not to the American market.

The increase in oil prices did not only bring benefits to oil producers, in the form of a huge increase in their wealth. It was a rude awakening for western consumers that they had to counter-balance this direct threat to their consumption habits and standards of living. Awareness about the security of oil supplies became widespread, resulting in the foundation of the International Energy Agency by the country-members of the OECD. At the same time, oil’s high price provided the incentive for oil exploration in ‘politically safe’ regions, the most notable being the North Sea and Alaska.

Although the existence of oil reserves in the North Sea was known since the 1960s, their exploitation was uneconomical. But with an international oil price high enough to cover the increased costs of offshore oil exploration, crude production in the North Sea covered a substantial part of the consumption requirements of the producing countries (UK, Norway, Netherlands and Denmark) and allowed modest exports.

In the United States, oil companies had been exploring in Alaska since the late 1960s, following the Suez Canal crisis in 1956. Their attempts had been largely unsuccessful, until Boxing Day 1967, when the ARCO-Humble venture struck a massive oil field at Prudhoe Bay. A few more drills confirmed that the deposit was of world class; in fact it ranked third, behind Saudi Arabia’s Ghawar and Kuwait’s Burgan. Despite the discovery, plans to extract the crude and transport it to the mainland were delayed for the remaining of the 1960s. The cost of extracting the oil under Arctic weather conditions was not economically viable. Furthermore, the entire endeavour was stymied by environmental groups’ protests and opposition to any plans for the construction of a Trans-Alaskan pipeline, which would damage irreparably the Arctic flora and fauna. After the rude awakening of the first oil shock, most environmental considerations were brushed aside and the Alaskan project progressed at a much faster pace. Proposals for alternative pipeline routes through Canada had been considered but, in the end, the pipeline from Prudhoe Bay to Valdez was favoured.

During the 1970s, the new jigsaw of the world energy markets was being painstakingly put together. OPEC countries rose to prominence, with the Middle East at the forefront. Western producers sought new secure sources of oil and, at the same time, stability in their relationship with the Middle East. The USSR edged its way into the international oil market, taking advantage of the high prices to replenish its hard currency reserves. High energy consumption and broad dependence on oil meant increased production costs and inevitable inflationary pressures. In fact, most of the oil producers’ incomes were being severely eroded by the dramatic increase in world inflation of the late 1970s. The bubble was again ready to burst; the Iranian Revolution kindly obliged.

World reaction to the second oil price shock was markedly different from that to the first. A number of important adjustments changed the structure of energy consumption post-1979. More specifically:

• Renewed emphasis was put on energy conservation and oil substitution, with the result that the non-Communist world’s oil consumption went into steady decline after 1979.

• There was a switch to politically safer sources of oil, boosting the production of non-OPEC countries, while dependence on OPEC oil fell considerably during the first half of the 1980s.

• The switch to new supply sources resulted in higher utilisation of heavier and sourer crudes; this urged many refiners to upgrade an increasing proportion of their facilities in order to improve the yield of lighter products from heavier crudes.

• The new price increase boosted immensely the fortunes of new, high-cost suppliers, like the UK, Alaska and Canada. In the UK alone, a brand-new industry was created almost overnight, giving a tremendous boost to the local and national economies.

The combination of a change to both demand and supply patterns resulted in a radical structural readjustment of the international oil trade. OPEC’s share in oil production fell by 45% between 1979 and 1985, while that of non-OPEC producers increased by 26% in the same period. The share of Middle East in world oil trade fell from 58% in 1978, to 42% in 1983; the US alone decreased its imports from the Middle East and West Africa by almost 75%, although its imports from Venezuela fell by less than 20%.

Faced with decreasing world demand for oil, and increasing competition from non-OPEC producers, the OPEC countries attempted to redress market conditions by reducing official prices, and by introducing quotas with a view to establishing some order among member countries. Following the radical change of the fortunes of OPEC producers, many of them had to compete in order to secure market share, thus resorting to price undercutting all too often.

With tension among OPEC members increasing, due to poor market conditions, Saudi Arabia played the role of the ‘swing’ producer, decreasing its production to accommodate the needs of other members. In the end, however, even the Saudis could not restore order in OPEC circles, and resorted themselves to quoting netback prices, pulling world oil markets to prices around $10/bbl.

The new situation was not desirable for oil producers, OPEC and non-OPEC alike. Market prices eventually recovered in 1987, and the new level of about $15-$18/bbl made oil popular once more, and led to a steady growth of oil imports, from about 24.5 mbpd in 1985, to 40 mbpd in 1998.  In terms of price fluctuations, of course, the situation remained as ‘interesting’ as ever. For most of the 1990s, the price fluctuated between $15 and $20 dollars per barrel (using Brent crude as a benchmark). Then in 1998 prices collapsed at below $15 to remain around $12/bbl for most of the year. Although this was good news to consumers around the world, the protracted price squeeze far from pleased state oil producers and oil companies alike. As a result, 1999 witnessed major restructuring in the oil sector, with extensive M&A activity, which culminated in the creation of ExxonMobil and BPAmoco, the latter eventually reverting to its original name, simply BP. At the same time, a regenerated OPEC managed to instil some discipline among its members, which adhered to their quotas, forcing the oil price to above $25/bbl in the space of a few weeks only.

Crude oil trade in the new millennium

As discussed previously, the new millennium brought with it hope for world economic growth, after the debacle of the Asian financial crisis at the end of the 1990s. China spearheaded this economic growth, on the back of a spectacular increase in energy consumption and trade, including crude oil, although it is only in the last five years that Chinese growth in oil imports has gained momentum. Overall, crude oil trade increased between 2000 and 2019, but it gained momentum from 2015 onwards, reacting to the relatively low oil prices during that period. As with production, crude oil trade was also affected by the Covid-19 pandemic and declined. Exhibit 21 shows this development, how it peaked in 2007, only to then contract in 2009 and 2010, before increasing again in the following two years and then picking up pace in 2015, before the 2020 dip and the partial recovery since 2022. Exhibit 22 shows a snapshot of crude oil trade in 2024 in the form of a flow diagram.

One final comment: since 2000 it has become increasingly apparent that the emerging economies of Asia Pacific generated the vast majority of growth in oil trade. Since the beginning of 2010, the region has become the main focus of oil exports, particularly by OPEC members and even more so by Middle Eastern members of the organisation. Exhibit 32 shows this in the context of all the crude oil flows out of OPEC members, whereas Exhibit 33 shows similar information but in the context of Saudi crude oil exports.

A brief history of pricing in the oil industry

Price volatility has characterised the oil industry since its beginnings in the 1860s. New discoveries attracted many wildcat drillers who pumped the new crude as quickly as they could get away with, flooded the market and caused prices to collapse. As soon as deposits were depleted, prices soared once more, until the circle was repeated with fresh discoveries. That situation changed when Standard Oil gradually took control of the industry at all stages of the supply chain: production, refining, transportation and retail sales. Until 1911, Standard Oil had an essential monopoly of oil in the United States.

The domestic US situation was not mirrored in the international oil market, however. American oil was competing with oil from Russia (extracted by the Nobel brothers) and Indonesia (produced and carried by Royal Dutch Shell). After 1911, the situation became more complicated. The dissolution of Standard Oil left the United States with a number of smaller companies with different expertise and different degrees of vertical integration. Some of the ‘baby’ Standards were in fact quite big, like the Standard Oil of New Jersey.  Most of the smaller ‘baby’ Standards, however, had to struggle to find new upstream suppliers – often abroad – or form downstream alliances with companies that had adequate retail sales networks.

In the meantime, the international market had two more contenders: the British company Burmah, which exploited the oil reserves in Burma; and Anglo-Persian, which was owned by the British Government, Burmah and private shareholders, and operated in Iran. Shell had ventured in the American market, with the foundation of Aguila in Mexico in 1919, after the demise of its Russian venture due to the Soviet Revolution. The picture was completed by Royal Dutch with its Asiatic ventures and a few minor producers like Romania. As all those companies were striving to secure supplies of crude and markets for their products, a price war, mainly between American and European companies, broke out which lasted almost until the end of the 1920s.

In August 1928, some of the most influential men in the oil business convened at Achnacarry in the Scottish Highlands: Henri Deterding of Royal Dutch Shell, Walter Teagle and Heinrich Riedemann of Standard Oil of New Jersey, Sir John Cadman of Anglo-Persian, William Melon of Gulf, and Col. Robert Stewart of Standard of Indiana. Although the meeting was to be on an informal and rather secretive basis, news of an oil company cartel soon leaked around the world. The agreement by the initial members of the cartel was to stop price wars and maintain current market shares intact. Although small at the beginning, the cartel had about 20 companies in the mid-1930s and controlled most of the international oil trade. The meeting remained known for posterity as the ‘Achnacarry’ or ‘As is’ or ‘Pool association’ agreement, and it was there that the Gulf-plus pricing formula was born.

This system was used by oil majors internationally until it was phased out soon after the Second World War. Prices were quoted on a CIF (cost, insurance, freight) basis, based on oil’s FOB (free on board) price at the US Gulf, plus the hypothetical shipment cost from the US Gulf to the final destination. The system essentially applied a blanket price for all crudes, irrespective of their origin, effectively overpricing Middle East crude exported to Europe and Japan.

Underlying Gulf-plus prices were US posted prices. These were standard wellhead prices for crude oil from local producing fields, quoted from individual US refiners. These prices represented domestic prices for the US market only and were often distorted by federal government controls. They were generally higher than the world market, reflecting the protectionism of US domestic oil markets. From 1974, however, US posted prices were generally lower than international prices, reflecting the attempt of the US government to dampen the effect of the huge increase in oil prices. After 1981, the Reagan administration phased out most controls on its domestic oil industry, so that US posted prices became directly competitive to export prices of non-US crudes.

After the Second World War the Gulf-plus system was terminated due to clamours from the British and American Navies, initially, and the European Co-operation Administration, which supervised the implementation of the Marshall Plan. Under this pressure, oil companies started quoting FOB prices ex-Middle East (in 1950) and ex-Venezuela (in 1952). The new system was known as the dual basing point system and was more representative of the international price of oil, rather than the US domestic market.

Meanwhile, in the Middle East, the end of the First World War left the Allies with a difficult problem to resolve: the dissolution of the Ottoman Empire. British, French and Americans were all very keen on the potential of the deserts of Iraq, primarily, and the Arab Peninsula. This led to the ‘Red Line Agreement’, as discussed earlier in this chapter, which formed the IPC consortium from co-operation in the upstream sector between Anglo-Persian, Shell, CFP and a consortium of American companies. The important development in this period was the change of the host-company agreement for the Iranian concession, which changed from profit sharing to royalty crude. This arrangement formed the basis of several subsequent host-company agreements around the world.

This gradual shift in the role of national governments in pricing oil did not start in the Middle East. From the beginning of the twentieth century, both the American and the British had shown interest in Mexico's potential as an oil producer. Yet, since 1917, article 27 of the Mexican Constitution named the state as the sole owner of the country's subsoil rights. Successive governments tried vigorously to enforce that article, resulting in a long dispute that was finally ended with the bitter retreat of both American and British interests in the country, after the Mexican government took complete control and agreed to compensate the companies.[14]

After the Mexico fiasco, the next obvious target for American oil companies was Venezuela, with its promising reserves under the bed of Lake Maracaibo. Although pressures for nationalisation were also strong in Venezuela, oil companies were essential for the development of the industry and were welcome, but the Venezuelan government clinched a 50/50 sharing agreement with the companies. The scheme meant that the government took 50% of the net profits of oil companies' operations after deduction of royalties and other contractual payments to the state. The ‘Venezuelan-style’ sharing agreement soon paved the way to improved remuneration of host countries for the exploitation of their natural resources and was later extended to the Middle East. 

Before that, Middle East governments collected 50% of oil companies’ profits from operations, but that 50% included royalties and other contractual obligations. Many countries felt that the ‘Middle-East-style’ 50/50 sharing was not adequate anymore. It was Iran that voiced its objection to, in fact, any sharing agreement at all, with the attempt of Prime Minister Dr Mossadegh to oust Anglo-Persian and nationalise the industry. Although that attempt was only short-lived, it set the tone for any subsequent sharing agreements between states and oil companies.

Iranian Nationalisation was only the beginning of what proved to be a long history of turmoil in the Middle East which revolved around the oil industry. Later in the same decade, the Suez Canal was closed by the Egyptian government, leading to a massive increase in transport requirements for oil, which now had to be transited round the Cape of Good Hope, resulting in shortages and rationing of oil in Western Europe.

The 1950s and 1960s also witnessed a considerable decrease in the price of oil in the open market. On the supply side, production was increasing, particularly in the Middle East, exerting downward pressure on posted prices (which can be seen in Exhibit 29, especially when looking at prices in current day money). This, coupled with the expansion of several independently owned refineries, gave rise to an increased number of arm’s-length deals, i.e. an open market in crude oil. By the end of the 1950s almost all arm’s-length deals were priced at a discount to official prices, a trend accentuated by the dumping of Soviet oil in the world market.

Depressed oil prices attracted the stern criticism of producing countries, resulting in the formation of OPEC in 1960. Soon enough OPEC countries asked the oil companies for ‘Venezuelan style’ 50/50 sharing. The compromise reached in the ensuing negotiations became known as the ‘OPEC royalty-expensing formula’, and essentially allowed a 50/50 sharing of profits after royalties, in return for several concessions on the part of host countries.

The persistent discounting of prices during the 1950s and 1960s made oil considerably cheaper than coal and boosted its share of total energy consumption in the Western world. The oil embargo and the second Suez closure in 1967 failed to interrupt the growth of oil consumption and trade, because Western European countries had accumulated considerable stocks, and were also able to import crude from countries outside the embargo which could import as much oil as they asked for from the Middle East. Shortages due to the longer haul around Cape of Good Hope were of no importance either, as a large part of Middle East crude was being carried by very large vessels (VLCCs), which could not transit Suez anyway.

Supply restrictions proved ineffective in raising oil prices, but it was excessive demand that spurred the first oil price shock. The first rumblings started with Colonel Qaddafi’s demand for increased Libyan postings, on the basis that Libyan crude should command a premium for its quality and proximity to Western markets. This led to the Tripoli Agreement in 1971, which allowed increased Libyan postings with a wide Libya-Middle East differential, no discounting of posted prices and a schedule for future increase of postings between 1971 and 1975.

In the meantime, the United States had dramatically increased its dependence on crude oil imports in the early 1970s, particularly so in 1973. A seller’s market was very much in place, but it was the oil companies that skimmed it. With the outbreak of the Yom Kippur war, the Arab producers seized their chance to flex their muscle and demand higher prices. On 16 October 1973 OPEC imposed unilateral postings increases, and the following day it also decided on production cutbacks.

It was at this time that official OPEC posted prices (or official OPEC postings) came into existence. These were the prices quoted by OPEC countries. Their determination represented the consensus of member-countries regarding their target prices, although they were at times violated by members. OPEC postings drove international crude oil markets from late 1973 to the first half of the 1980s. Prices were quoted for the Saudi Arabian 34º API light crude, FOB  Ras Tanura, which was the marker or benchmark crude. Most other OPEC crudes were priced as discounts or premiums to Arabian light. Nowadays, many OPEC members still quote their own posted prices, which are usually calculated on the basis of one or more benchmark crudes, typically Brent, WTI or Dubai-Oman, depending on which market the oil is sold to.

Although the whole OPEC movement looked well-orchestrated, it was in fact improvised along the way. There was no initial agreement over market shares among OPEC members, whose national interests frequently came in conflict. Some countries pushed for successive increases, others advocated restraint. The result was a stop-go pattern of oil price increases, which eventually stabilised above $10/bbl, in nominal terms, although in real terms the price of oil decreased through the 1970s. The Iranian Revolution and the outbreak of the Iran-Iraq war spurred fresh confusion in the oil market. Libya, on the one hand, followed a ‘leapfrogging’ pricing tactic, while Saudi Arabia tried to moderate the situation by adopting a price of $24/bbl, and advising restraint. It was only in June 1980 that OPEC managed to determine a price band of $32-$37 which was acceptable to all members.

The new market situation prompted the increased participation of non-OPEC producers in the international oil market, both for security reasons but also because the new higher prices incentivised exploration and production of oil in areas where it far more expensive. The availability of several independent suppliers – i.e. not controlled by the state or any major oil company – coupled with the dismantling of the remaining price controls in the US market, gave way to a more transparent and liberal trading environment, at least in the US and Western Europe. One major piece in the new jigsaw was North Sea oil. The production of Brent crude in the UK sector was in direct competition with Nigerian Bonny Light crude, both in terms of quality and in terms of markets. As most of Nigeria's revenues came from oil exports, the country's economy was particularly hurt from intense competition by Brent. As a result, Nigeria started undercutting OPEC's official posted prices, with the aim to recapture market share.

The lack of production and price discipline within OPEC resulted in spot oil prices spiralling downwards, becoming more and more out of touch with the organisation’s official postings. OPEC’s dismay was exacerbated by the world economic recession which resulted in falling demand for energy worldwide, and the scramble to replace oil with other energy sources, such as coal, which eroded oil’s share in primary energy consumption. OPEC remained a substantial, but residual, producer. Within OPEC, Saudi Arabia remained the swing producer. With tumbling oil prices, however, Saudi Arabia resigned its role in 1985 and started quoting prices to refiners on a netback basis. In general, netback prices were prices attached to crude oil, which have been calculated from prices of products, using the netback method. This means that the crude oil price is the residual of the products’ price after subtracting the refiner’s profit margin, the cost of refining and the cost of transport and insurance. This system means, of course, that the crude producers effectively accept the market risk, and at the same time guarantee the refiner’s profit.

Physical crude markets

The discussion of oil’s physical characteristics earlier in this chapter implies that there is a large variety of crude oils available in the open market, most of which are priced on a purely competitive basis. It is, therefore, important to know the physical characteristics, as well as the location of a particular crude, as these are key determinants of its final price. One such market that developed and matured in the 1980s is the market for Brent crude, which is extracted in the British sector of the North Sea. The presence of Brent crude prices in the pricing formulae of several crudes around the world justifies its placement at the top of the list of the crude oil covered in this section.

Historically, it was in 1976 that the first consignments of Brent crude were loaded at Brent Spar, and in 1979 the terminal at Sullom Voe in the Shetland Islands became operational. In the early 1990s, the production of Brent blend amounted to about 850 Kbpd. In the early 2000s this figure was more than halved, and nowadays industry estimates put the production of the Brent and Ninian fields to ca. 200 Kbpd. The rapid decline of the physical base Brent blend created the potential threat of price manipulation, which would have undermined the position of Brent as a world pricing benchmark for oil. This was quickly addressed by the industry from the early 2000s and the result was the addition of three more North Sea crude oils in the physical base: Forties and Oseberg (in 2002), Ekofisk (in 2007) and Troll (2018); the first is in the UK sector, the latter three in the Norwegian sector of the North Sea. All of them together form BFOE (the 'T' had not entered the acronym at the time of writing), the physical base which is still conventionally referred to as “Brent crude”, with their combined production amounting to ca. 1 mbpd.

Brent blend is denominated as a light, sweet crude, with a specific gravity of 38.5° API and a sulphur content of 0.41%. Its constituent crudes, however, have a specific gravity in the range of 30°-40° API, and a sulphur content of 0.2-1%. Standard quality is of course important, since market participants expect at least some security in terms of the blend’s properties.

Another key issue is the ownership of the fields, as control by a limited number of companies might create oligopolistic tendencies and, hence, supply squeeze. In the case of the North Sea fields, including Brent, the UK government ensures that ownership interests are as widespread as possible. In 2018, for example, there were over 150 companies with ownership interests, but the ownership structure is never the same, as takeover activity is considerable. Some companies, however, are more important than others, in terms of ownership shares in – or entitlements to – Brent blend. The leading companies are Shell, ExxonMobil, BP, Chevron, Total and CNR, with Shell (who made the first discovery of this crude and named the field) being the key operator.

Brent is very much an international crude, with the majority of it being exported. Nowadays most of the exports are directed to Europe, with Rotterdam in the Netherlands and Wilhelmshaven in Germany the main recipients. There are, however, other flows across the Atlantic to the United States and Canada and even further away to South Korea. In the US market, if still imported, Brent competes with other domestic light sweet crudes, such as WTI, or imported ones, such as Nigerian Bonny Light.

Brent is one of a number of crude oils produced in the North Sea. In the UK sector blends from the Forties and Flotta sectors also compete in the export markets and the former is already included in the BFOE physical base, as discussed earlier on. Exhibit 36 shows Brent spot prices since the early 1970s, annotated with key events in its history.

In the Norwegian sector, the most prominent fields are Ekofisk, Oseberg, Troll, Statfjord and Gullfaks. All of them enter the international market, as most of the Norwegian production is exported. The first two are already part of the BFOE physical base, whereas the other two are priced against Brent/BFOE. Norwegian crude production is primarily exported to European countries, with the United Kingdom being the major customer, followed by the Netherlands, Sweden and Germany. Some of the non-European importers of Norwegian production are the United States, South Korea and Canada.

WTI and other North America

While Brent crude is an extremely important benchmark for world oil prices, it is still in competition with what used to be the original pricing benchmark – WTI. It is worth remembering that the United States is the world’s largest consumer of oil, accounting for nearly 20% of world consumption, and is also the world’s largest importer. Simultaneously the country is also the world’s third largest producer, with an output of crude oil and NGLs at over 15 mbpd in 2018, which has been boosted since 2011 by the advent of shale oil. Historically, there have been several crude oils which are traded heavily, albeit only domestically, as crude oil exports were banned since the mid-1970s. In early 2016, the 40-year export ban was lifted by Congress and the US has been an increasingly active exporter. The country itself is divided into five Petroleum Administration for Defence Districts (PADDs): East Coast (PADD 1), Midwest (PADD 2), Gulf Coast (PADD 3), Rocky Mountain (PADD 4) and West Coast with Alaska and Hawaii (PADD 5) - Exhibit 37 shows the five districts and which states they include. Of these districts, the most important one is PADD 3, which produces nearly 60% of total US crude oil. PADD 3 includes Texas, the biggest producing state, and the federal offshore fields in the US Gulf, which collectively form the second largest producing region. This district also holds half of the country’s operable refining capacity, ca, 10 mbpsd (of a total 19 mbpsd) as of January 2021.

The most prominent crude in the United States, West Texas Intermediate, is a blend of several crudes with specific gravities between 34°-45° API and sulphur content below 0.5%. The par grade is 40° API and has 0.4% sulphur content, which is slightly lighter and as sweet as Brent. The physical base consists of crude deliveries at the end of the pipeline or suitable storage facilities at Cushing, Oklahoma. Although WTI is the par grade, there are several other crude oils that are actively traded. Sweet light crudes, similar to WTI include: Louisiana Light Sweet (LLS), New Mexico Sweet, Oklahoma Sweet, South Texas Sweet, Low Sweet Mix (Scurry Snyder). The list does not stop there, however. The offshore fields of the US Gulf yield a number of different grades, including Mars, Thunder Horse, SGC (Southern Green Canyon), Poseidon and Eugene Island, all of them heavier and sourer that WTI. The list of PADD 3 grades would close with West Texas Sour and Heavy Louisiana Sweet, if it were not for the most recent and most exciting addition: Eagle Ford. This is a shale play that yields a number of different qualities, all of them very light (condensates) and sweet (see Exhibit 38).

Another important crude is the one produced in Alaska. Alaskan North Slope (ANS) is a relatively sour and heavy crude, which is extracted from the fields in the North of Alaska at Prudhoe Bay and then moved via the Trans-Alaskan pipeline to Valdez. From there, it is shipped by tankers to the US West Coast and the US Gulf. The picture of crude oil production in the United States is completed with the Bakken shale play in the north of the country, in the states of North Dakota and Montana, as well as the Canadian provinces of Manitoba and Saskatchewan.

Over the border in Canada, crude oil production boomed throughout the 2000s. The existence of oil-bearing sands had been known for nearly three centuries and production attempts had been made since the late 1960s. The international oil price, however, was not high enough to justify production at such a high cost. Yet with oil prices on the ascent since 2000, production came on stream again in 2003 and has expanded since then. Today Canada is the world’s eighth largest crude oil producer and third largest reserve holder, behind Venezuela and Saudi Arabia, with over 170 billion barrels. Around half of its production comes from the Alberta oil sands, with the rest coming from the eastern Canadian provinces, such as Ontario, Newfoundland and Nova Scotia. From the eastern provinces come grades such as Terra Nova, Hibernia and White Rose, all medium to light sweet varieties. Alberta provides grades such as Lloyd Blend (a heavy and very sour grade), Mixed Sweet and Light Sour Blend, as well as Syncrude Sweet. The latter is produced after extracting bitumen from the oil sands and upgrading it to light crude by fluid coking, hydroprocessing, hydrotreating and reblending. The result is known as synthetic crude oil (SCO) or Syncrude and is shipped via pipeline to Canadian and US refineries.

Dubai and other Middle East Gulf

The Middle East is the biggest exporter of crude in the world and plays, therefore, a key role in regulating the supply side of oil trade. The role of the Middle East was extensively discussed earlier in the chapter, so there is no need to repeat it in this section. As we know, Saudi Arabia is the world’s largest producer and exporter and produces a variety of crude grades, from the Arab Heavy to the Arab Extra Light. For many years, one of the most commonly quoted crudes for many years was Arab Light, and it still is one of the twelve constituent crude oils of the OPEC basket.

Since the 1980s, Dubai crude oil has been steadily rising as a new pricing benchmark, particularly for cargoes delivered East of Suez, mainly to Asia Pacific. This is a medium crude of approx. 31° API and contains around 2% sulphur. Its physical base has been steadily declining, so now it relies on two other regional crudes, Oman and Upper Zakum (Abu Dhabi), which are of similar quality and which can be delivered in lieu of Dubai.

There are several other crude oils in this area, as it produces substantial amounts of both oil and gas, which are exported to the international market. These include: Basra Light (Iraq), Murban and Lower Zakum (Abu Dhabi), Qatar Land, Qatar Marine, Ras Gas condensate and Shaheen (Qatar), and South Pars condensate from Iran.

West Africa

A considerable amount of international oil trade is generated from the west coast of Africa, where the producing countries are Nigeria, Angola, Gabon, Congo, Cameroon and more recently Ghana. Their target markets are primarily transatlantic, notably the United States, but also Europe. In recent years, the other prime destination, particularly for Angolan crude oil, has been China. There are several types of crude coming out of the region, some better known than others. Historically, Bonny light has been the most well-known and is also one of the twelve OPEC basket crudes. Other grades include: Forcados, Escravos, Brass River and Qua Iboe from Nigeria; Cabinda, Kuito, Nemba and Girassol from Angola; Kole and Lokele from Cameroon; N’Kosa and Djeno from Congo; Mandji and Rabi Light from Gabon; and Jubilee from Ghana. All of the above crudes mainy use Brent as a marker crude, but pricing on WTI is not uncommon, especially for cargoes destined for the US Gulf.

Black Sea/Mediterranean

In the Mediterranean the main producers participating in the spot market have traditionally been Libya, Egypt, Syria, and Algeria. Iran and Russia are also very active and important despite not having a Mediterranean coast. Iran uses the SUMED pipeline which receives oil at Ain Sukhna in the Red Sea and transfers it to the Sidi Kerir terminal on the Mediterranean coast of Egypt. Russia has now consolidated its position as the world’s second largest exporter. The main Russian crude grade is Urals, a medium sour crude, which is transferred via a network of pipelines to the port of Novorossiysk in the Black Sea, from where it is shipped in tankers through the Bosporus and on to its final destination. Urals crude is also exported via Russia’s ports in the Baltic Sea, Primorsk and Ust-Luga. In addition to Urals, Russia produces Siberian Light, a light and sweet grade, which it also exports via Primorsk and Novorossiysk.

The latter port is also the recipient of crude oil from Russian production platforms in the Caspian Sea, as well as large quantities of Tengiz, a light and sweet crude produced in the Kazakh section of the Caspian Sea. This is done via the CPC (Caspian Pipeline Consortium) pipeline, which delivers its CPC Blend to Yuzhnaya Ozereevka, near Novorossiysk. Kazakhstan also produces the Kumkol grade further to  the East of the country which it plans to exports to China with the construction of the Kazakhstan-China pipeline from Atasu to Alashankou, which will connect to Kumkol and extend further westwards to eventually connect to Atyrau in the North of the Caspian Sea and the beginning of the CPC pipeline. Strategically, this is important for Kazakhstan as it will allow the country to market the production from its most recent project, Kashagan, both to the West and the East, depending on prices and contractual commitments.

The third crude oil producer in the Caspian Sea is Azerbaijan. Its Azeri Light, a medium to light sweet crude, is exported from the port of Baku, via two pipelines. The Baku-Supsa pipeline carries the oil to the Georgian port of Supsa on the Black Sea coast, from where it is loaded on tankers. The BTC (Baku-Tbilisi-Ceyhan) pipeline takes the oil from Baku, via Tbilisi in Georgia and then down to the port of Ceyhan in the Southeastern corner of Turkey, from where it is also loaded to tankers for export. From Syria come two rather small streams of crude, Syrian Light and Souedie, a heavy and very sour crude. However, under the current (2014) political climate, not much finds its way to the international market. 

Coming now to the main Mediterranean basin, there are several crude oils that are traded alongside Urals, CPC and Azeri Light. From Egypt comes the Suez Blend, a medium sour grade, alongside Iranian Heavy and Iranian Light crude (provided the embargo on Iranian oil is terminated), which are lifted at Sidi Kerir. Iraqi Kirkuk Blend is exported from the Kurdistan region of the country’s north, via the Kirkuk-Ceyhan pipeline, to the port of Ceyhan. Moving on towards the western part of the Mediterranean, Algeria and Libya are the other two main exporters. Algeria’s Saharan Blend and Zarzataine are both light sweet crude oils. Libya’s Es Sider, on the other hand, is slightly heavier, but still a very important oil for European markets, especially for Italy.

Latin America

Latin America has been an important oil producer and exporter since the early twentieth century. The natural destination for exports from this region is the United States. In 2018 the US sourced 9% of its imports from Mexico and smaller flows from Venezuela, Colombia and Brazil.

Venezuela is of course the world’s largest reserve holder and PDVSA, the state oil company, produces a number of different grades of crude oil, most of the heavy to medium and sour variety. Bachaquero is the best known of Venezuelans grades and Merey is the one included in the OPEC basket. Both of them are very heavy and sour, in the range of 12-16º API, and sulphur content of ca. 2.5%. Other grades include Tia Juana Light and Mesa 30, both of which are medium and sour.

Mexico has been a long-standing exporter, particularly to the United States. The country was among the first to nationalise its hydrocarbons and did so in 1938. After 75 years, Mexico finds itself with declining production and exports and with great difficulties to incentivise foreign oil companies to come and boost its exploration efforts. Its main crude grade is the heavy and sour Maya, most of which is exported to the United States. Isthmus and Olmeca are its lighter grades, which tend to be directed to Mexico’s own refineries.

Brazil has taken over from Venezuela as Latin America’s largest producer, with ca. 3 mbpd in 2020. Domestic consumption of ca. 2.3 mbpd means that the country is a net exporter. Over 90% of its crude oil comes from offshore fields and is, unusually, heavy sweet. Typical grades are Marlim and Roncador. The country’s position as a sizeable oil producer has been boosted further with the development of its Libra oilfield. In recent years, Brazil has turned from a net importer to sizeable exporter, particularly to the North American and European markets.

Colombia is a relatively small producer, compared to its South American neighbours, but its production has increased steadily since 2008 due to increasing exploration and development. Its crude oil is mostly heavy and sour, with Cano Limon the lightest and relatively sweetest of the lot. The remaining countries in the region are relatively less significant oil producers, although several crude grades find their way to the international markets. Argentinian Escalante, Ecuadorian Oriente and Peruvian Loreto are such examples. Again, all of them are relatively heavy crudes (19-24º API) and mostly sour.

Asia Pacific

As a region, Asia Pacific is in huge deficit in terms of oil. According to BP, the region produced 7.4 mbpd in 2020 and consumed 33.6 mbpd in the same year. Inevitably, the region relies on substantial imports, particularly from the Middle East, West and North Africa and Russia. 

Half of the region’s production comes from a number of onshore and offshore fields in China. There are several grades, some which are Daqing, Nanhai Light and Shengli. They have a range of qualities, from sour, to light and varying degrees of sulphur content. Indonesia is another established producer, although its declining production made the country a net importer and caused it to lose its place as an OPEC member. Still, there are several streams of Indonesian crude that are traded regionally. The longest-standing one is Minas, but other grades include Attaka (light), Duri (heavy) and Senipah (condensate), although this list is far from exhaustive.

Malaysia’s Tapis light, sweet crude oil is extensively traded regionally and used as a key local benchmark in Singapore. Other Malaysian grades traded regionally are Miri Light and Labuan. The two relatively most recent participants in this regional market are Australia and Vietnam. Both countries have intensified their exploration and production efforts in the last decade. Vietnam’s Bach Ho and Australia’s Gippsland are the two most commonly traded crude grades, although other grades like Su Tu Den, Cossack and Enfield are also traded in the region.

Finally, Russia is also a keen exporter to the region of oil produced in several fields in Eastern Siberia. The production from these fields is collected by the ESPO (East Siberia Pacific Oil) pipeline, which delivers the light and sweet ESPO Blend to the port of Kozmino, from where it is lifted by tankers for delivery to Chinese, South Korean and Japanese buyers.

Pricing methodology

Historically, crude oil has been sold on the basis of long-term contracts, sometimes as long as the life of a particular field. Life-of-field contracts rarely exist nowadays, if at all. Term contracts do exist of course, but the way they are priced has also evolved during the course of oil’s history. Whereas term contract quantities and prices were all fixed at the beginning of the contract, the increased irritation of host producing countries regarding the prices paid to them by western oil companies, meant that the original term contracts had to be replaced with ones which allowed at least some degree of price renegotiation, driven by market demand and supply dynamics.

As discussed earlier in this chapter, oil pricing has evolved from being dictated by international oil companies, to being negotiated between the same companies and host nations asserting their right to extract a higher economic rent for their natural resources. It progressed to administrative pricing by OPEC members and finally to a brief period of netback pricing: crude oil prices were pegged to the prices for refined products as competitively determined in the open markets of developed economies. For a more detailed review of the evolution of oil pricing and a detailed discussion of the current pricing system, see Fattouh (2011). From 1986 onwards we have witnessed the transition of the oil pricing mechanism to a market-led system, with spot physical transactions for a multitude of crude oil grades of different specifications and locations on the one hand, and on the other a number of layers of derivative paper products, including futures, options, swaps, some of which are traded in commodity exchanges and some as over-the-counter (OTC) products. In this section we focus on the pricing of physical crude oils using a number of benchmark crudes and how these benchmarks operate. We defer the discussion on derivative products for later in the text.

The side effect of the third oil price shock of the mid-1980s and in part what led to the emergence of the spot – or cash – market and prices. These are prices quoted in one-off, arm’s-length deals. Before the 1980s spot prices were quoted primarily for refined products. If there were any occasional spot market transactions for crude oil, there was no publicly reported information about them, so that spot prices for crude oil were inferred from product prices. 

Although the term ‘spot’ may allude to the immediacy with which a cargo of oil is delivered, this is not true and in fact impractical. Firstly, the oil itself needs to be produced, perhaps blended and then placed in port/terminal storage tanks awaiting lifting. Even when spot transactions are done on an FOB (free on board) basis, which is the norm, there is a time lag between agreeing the purchase and lifting it. The next phase involves waterborne transportation, typically by large crude oil carriers, with voyages lasting from a few days (say from North Sea to Northwest European ports), to a few weeks (say from Middle East Gulf to Pacific Rim ports) or even over a month (say from Middle East Gulf to US Gulf ports via Cape Good Hope). When the transaction takes place after lifting, which is quite common in the oil industry, further adjustments are made to the final price, which is now a CIF (cost, freight and insurance) basis or any other contract terms that make the seller more involved in the delivery of the cargo to the buyer. In both cases, it is quite common to price the cargo around the time of its lifting from the export terminal (FOB basis), or its arrival at the final destination (CIF basis).

In addition to the prevailing contract terms, the price for a particular crude oil Pc is determined on the basis of a formula like Pc = PB ± Δ where PB is the benchmark price and Δ is the differential. So, at the minimum, a particular crude oil will trade at a premium or a discount to the benchmark price and the differential may depend on a number of factors, including quality, desirability of the particular crude, availability of other competitive crude grades and so on. This means that both the underlying benchmark price and the differential can and will fluctuate. 

Following on from this, it is now common to use spot prices, or rather an agreed spot price average, to price term contracts, in some cases on a cargo-by-cargo basis. So although the contractual agreement to supply/purchase the crude oil is long-term, the price is set on a much more short-term basis and is market-driven. 

The final link in this pricing system is the existence of a reliable source of market information on the various crude oils and, especially, the benchmarks. This is a function performed by the price reporting agencies, or PRAs. There are two main PRAs, when it comes to crude oil prices – Platts (owned by publishers McGraw-Hill) and Argus Media (thereafter Argus). There are a few more PRAs publishing price information for refined products and chemicals, but Platts and Argus are the de facto market leaders. What the PRAs deliver is a series of price assessments at the end of every day. They do this by contacting market participants (oil majors, upstream producers, oil traders, refiners and so on) to ascertain whether they have bought/sold specific cargoes and from/to whom. They then cross-check this information with the respective counterparties, in order to establish the accuracy of the information and whether it can be included in the calculation of the bid-ask price range for the particular crude oil for the day. The two PRAs follow slightly different methodologies.

Brent pricing

Brent production was boosted after the first two oil price shocks, when it became profitable to extract the high-cost oil situated under the very dangerous rough waters of the North Sea. This new light sweet crude was not only used in the domestic UK market, it was also sought after by many refiners in developed economies on both sides of the Atlantic. Its quality made it highly competitive against West African crude oils, primarily Bonny Light, and its production in a politically safe environment meant that supply disruptions were highly unlikely. The licensing system used by the UK government ensured that Brent had widespread ownership, so that no individual producer could squeeze the market in order to raise prices artificially.

High quality, which leads to high marketability, and broad ownership are the two fundamental pre-requisites for the establishment of a price benchmark in any market. With NYMEX light sweet crude (essentially WTI) fulfilling this role in the US domestic market, Brent became the obvious choice for internationally traded crude oil. The market developed on two levels: ‘wet’ cargoes which were due for delivery in the next 10-30 days; and ‘paper’ cargoes, or forward contracts, which were bought and sold between market participants, until they were eventually linked to specific cargoes with a particular delivery window. The two markets that developed were Dated (DTD) Brent and month-ahead (or forward or paper) Brent, respectively. Over time, the declining quantity of physical Brent necessitated the inclusion of additional North Sea crude oils to increase the physical base to what is now the BFOE, as discussed earlier in the chapter. In addition to this, the pricing window for Dated Brent has expanded from 7-15 days, to 10-25 days and currently to 10-M+1 (month-ahead), in order to allow more cargoes to enter the pricing window and ensure that the prices are truly competitive. As a result, the forward market for Brent is known as month-ahead (M+1) Brent (or month-ahead BFOE), reflecting the arrangements in the pricing process of Dated Brent. Let’s now have a look at how this process works.

The orderly operation of Dated (DTD) Brent is important to ensure its price formation is not subject to unexpected disruptions, given that it is used to price so many other crude oils around the world. There is, therefore, a standard procedure for its delivery, which consists roughly of the following steps:

• Equity holders nominate their intention to deliver Dated Brent cargoes (which can be any of the BFOE constituent crude oils) to be produced in any month by the end of the second month before delivery month. Soon after that, the loading schedule is released. For example, loading dates for cargoes to be delivered during November are released by the end of September.

• Cargoes are lifted in standard parcels of 600,000 bbls, with a tolerance of ±1%, i.e. ±6,000 bbls. For standard Brent quality this would equate to ca. 79-80,000 tonnes, the size of a typical Aframax tanker.

• Each cargo is given a number and a loading (or lay-can) window, during which the cargo has to be loaded on a designated vessel. Each window is typically three days long, with the first day of the first window starting on the first day of the month, and the last day of the last window ending on the last day of the month. So, for November cargoes the first window (assuming a 3-day lay-can) would be 1-3 November, and the last 28-30 November.

These specific dated and numbered cargoes form the basis of the physical Brent/BFOE market. These are the cargoes that are bought/sold between market participants in the spot market. As mentioned earlier, spot does not mean immediate delivery in the oil market. Typically, it implies a time lag between the transaction and the actual cargo delivery. In this market the earliest delivery is normally ten days after the spot transaction and the delivery window can extend to 30 days forward. For this reason, when the PRAs assess spot prices, they refer to them as Dated Brent/BFOE prices for loading 10-month ahead. For example, on October 20th, price assessments will be for cargoes due to be delivered between October 30th and November 20th. Price assessments on October 21st will be for cargoes to be loaded between October 31st and November 21st and so forth. Platts publishes these assessments under the name ‘Dated Brent’, whereas Argus uses the name ‘North Sea Dated’. The underlying commodity is the same (one of the four BFOE constituents), the principle of the assessment is the same (the most competitive of the four grades on each day), but the methodology of the calculation is different (Platts uses MOC and Argus uses averaging).

Given the nature of the Dated Brent/BFOE market operations and the size of each parcel, the Dated Brent market is really for large companies, who either need the cargoes for their own refineries or to sell them to international buyers. These companies are usually oil majors, independent oil traders, independent refiners, upstream producers and occasionally financial institutions who may have a presence in the physical North Sea oil market.

Having summarised how the Dated Brent market works, we now turn to the month-ahead cash BFOE, essentially the forward market for BFOE. As far as forward markets are concerned, this is an unusual one, in that practically all the aspects of the contract are standardised, rather than customised. The cargo parcel is standard at 600,000 barrels (although partial cargoes of 100,000 barrels are also possible), the quality of the cargo is standard (current quality Brent-Ninian Blend, Forties, Oseberg or Ekofisk, the latter three with appropriate price adjustments for quality) and so is delivery (Sullom Voe or appropriate terminal for each grade). What remains unknown for both transacting parties is the precise loading window for the cargo and of course the price, which is negotiable.

Forward BFOE contracts can be bought/sold between parties for delivery as far in the future as the two parties wish, but for practical purposes it is the next three months forward which are more actively traded and for which the PRAs provide daily price assessments. Contracts for month-ahead cash BFOE can be sold and bought at any point in time, all the way up to one month before the delivery date (the first day of the 3-day loading window) of the Dated Brent cargo. After this deadline, the particular month-ahead BFOE becomes ‘wet’ and can only be traded as Dated Brent. Based on this principle, the front (next forward) month becomes ‘wet’ when its first cargo becomes ‘wet’, which is on the last day of the month two months before the delivery month. For example, July month-ahead BFOE will expire on May 31st. On June 31st, August becomes the front month, September becomes the second month and October becomes the third month.

For the market participants there are two ways to clear their positions – nominations or a paper, cash or dry book-out. Once the seller of a month-ahead BFOE contract has the precise details of a cargo (number and lay-can) he can hand a nomination, i.e. a document notifying the details of the cargo, to the buyer. At this point the buyer can: (a) hold on to the nomination and sell it on as a Dated Brent cargo; or (b) hold on to the nomination and take delivery of the cargo, in which case he has to nominate a vessel to lift the cargo; or (c) pass the nomination to another party to whom he had sold a month-ahead BFOE contract at a different point in time. If the buyer chooses (c), this is known as ‘passing the parcel’ and can continue up to 5.00pm London time, one month before before the first day of the lay-can for the specific cargo.

Usually, buying or selling month-ahead BFOE contract is done purely for hedging or speculation purposes. As a result, a party may have bought a cargo at one point in time for delivery in a specific month and at another point in time he may have sold another cargo for delivery in the same month. In a typical futures market, say the Intercontinental Exchange where Brent futures contracts are traded, this would be equivalent to the party reversing their position, cashing their profit or loss and exiting.

WTI pricing

Like Brent, WTI is a very actively traded crude oil and it has a long history as a price benchmark, both for the US domestic, as well as the international, market. Unlike Brent, WTI has a much simpler pricing structure and a much more straightforward link with the light sweet crude oil contract traded on NYMEX, which is now part of the CME Group. This futures contract was launched in March 1983 and rose to prominence during the third oil price crisis in 1986. With the world economy in recession and demand for oil, especially OPEC oil, suffering, OPEC members struggled to keep to their quotas and tried to undercut each other’s prices in spot market sales in order to gain market share. Eventually this prompted Saudi Arabia, the swing producer who kept decreasing its production to maintain the overall quota levels, to resort to netback pricing. With netback prices in force, it became paramount to have a market-determined price for refined products, from which refining margins and transportation costs could be deducted, in order to calculate the next price of the crude oil payable back to the producers. Since late 1978, a heating oil futures contract was traded on NYMEX. With the introduction of the light sweet crude contract the netback link between products and crude was established. As the United States was very much the dominant demand market for crude oil and refined products, the world looked to the futures market in New York to establish a world price for crude oil. WTI, the main physical crude oil deliverable against the futures contract, became the de facto world benchmark.

The physical base of WTI has already been described earlier in this chapter. Physical trading takes place at the pipeline hub in Cushing, Oklahoma and the crude oil is delivered at the end of a pipeline or in suitable storage tanks in the area. The physical delivery of WTI and other acceptable substitutes is specified in the CME/NYMEX traded contract.

“Delivery shall be made free-on-board ("F.O.B.") at any pipeline or storage facility in Cushing, Oklahoma with pipeline access to Enterprise, Cushing storage or Enbridge, Cushing storage. Delivery shall be made in accordance with all applicable Federal executive orders and all applicable Federal, State and local laws and regulations.

At buyer's option, delivery shall be made by any of the following methods: (1) by interfacility transfer ("pumpover") into a designated pipeline or storage facility with access to seller's incoming pipeline or storage facility; (2) by in-line (or in-system) transfer, or book-out of title to the buyer; or (3) if the seller agrees to such transfer and if the facility used by the seller allows for such transfer, without physical movement of product, by in-tank transfer of title to the buyer.”[15]

The WTI contract is more flexible that Dated Brent, with contracts only 1,000 barrels large and deliveries typically in parcel of 50-100,000 barrels. The WTI futures market is also very forward-looking, with months open until 9 years ahead. More specifically, consecutive months are listed for the current year and the next five years; in addition, the June and December contract months are listed beyond the sixth year. Finally, WTI contracts are also more flexible than Brent contracts, in that they allow a considerable number of alternative crudes to be delivered: specific domestic crudes with 0.42% sulphur by weight or less, not less than 37° API gravity nor more than 42° API gravity. The following domestic crude streams are deliverable: West Texas Intermediate, Low Sweet Mix (Scurry Snyder), New Mexican Sweet, North Texas Sweet, Oklahoma Sweet, South Texas Sweet. Also, specific foreign crudes of not less than 34° API nor more than 42° API are deliverable. The following foreign streams are deliverable: UK Brent and Forties, and Norwegian Oseberg Blend, for which the seller shall receive a 30¢-per-barrel discount below the final settlement price; Nigerian Bonny Light and Colombian Cusiana are delivered at 15¢ premiums; and Nigerian Qua Iboe is delivered at a 5¢ premium.[16]

Despite all these attractive attributes, in recent years WTI has lost its crown as the world’s prime crude oil benchmark, while Brent has consolidated itself in this role. Increasingly, WTI is a US domestic benchmark, with prices used for other US crude oils, as well as cargoes imported into the North American market. The relationship between WTI and Brent is often observed in the co-movement between their two prices. Historically and all the way up to 2010, WTI prices have been above those for Brent. The explanation was quite straightforward: the differential was due to quality and location. Brent was a crude imported into the United States and to make it competitive with WTI, it needed an FOB price below that of WTI, to reflect the slightly lower quality and also the freight that had to be added to deliver Brent to US refineries. Exhibit 41 shows the spot price series for the two benchmarks since the beginning of 2000 until the end of November 2019, plotted as solid lines and measured on the left axis. Their price differential (Brent minus WTI) is plotted as an area and measured on the right axis. It is evident that until mid-2010 WTI traded above Brent, with the WTI premium fluctuating mostly around $0-5/bbl, although in some instances it did trade at a discount. From mid-2010 onwards, however, the WTI discount versus Brent has been consistent and even exceeded $25/bbl between August and October 2011. More recently, the discount has shrunk and is currently (July 2021) less than $10/bbl.

Despite all these attractive attributes, in recent years WTI has lost its crown as the world’s prime crude oil benchmark, while Brent has consolidated itself in this role. Increasingly, WTI is a US domestic benchmark, with prices used for other US crude oils, as well as cargoes imported into the North American market. The relationship between WTI and Brent is often observed in the co-movement between their two prices. Historically and all the way up to 2010, WTI prices have been above those for Brent. The explanation was quite straightforward: the differential was due to quality and location. Brent was a crude imported into the United States and to make it competitive with WTI, it needed an FOB price below that of WTI, to reflect the slightly lower quality and also the freight that had to be added to deliver Brent to US refineries. Exhibit 34 shows the spot price series for the two benchmarks since the beginning of 2000 until the end of November 2019, plotted as solid lines and measured on the left axis. Their price differential (WTI minus Brent) is plotted as an area and measured on the right axis. It is evident that until mid-2010 WTI traded above Brent, with the WTI premium fluctuating mostly around $0-5/bbl, although in some instances it did trade at a discount. From mid-2010 onwards, however, the WTI discount versus Brent has been consistent and even exceeded $25/bbl between August and October 2011. More recently, the discount has shrunk and is currently (July 2025) less than $5/bbl.

Why is this then? Market analysts have identified several causes for the fluctuation of the Brent-WTI spread. The large discount of WTI against Brent was primarily due to the increased domestic shale oil production, which created a glut; the irreversibility of domestic oil pipelines which at the time were geared towards receiving, rather than exporting, the various crude oils; and the short supply of storage facilities.

Dubai pricing

Dubai is the newest of the three benchmark crudes and gained prominence from 2000, when the ascent of emerging economies in Asia Pacific meant that much larger quantities of crude oil, especially from the Middle East and West Africa, found their way into the region. Dubai is a Middle Eastern crude oil, coming from the smallest emirate (in terms of oil output). Although it was produced in relatively small quantities, it was one of the very few Gulf crudes that could be traded in the spot market. The rapid decline in the production of Dubai crude has created a similar situation to that for Brent. Although Dubai is still the name of the benchmark, it is frequently Oman or Upper Zakum crude that is delivered instead, as Dubai crude production is estimated to be below 60 Kbpd. As Fattouh (2012, p.3) notes “Dubai has turned into a brand, or index, representing a basket of mid-sour crudes.” These are crude oils travelling predominantly from the Middle East to Asia Pacific, a trade flow that has grown substantially in recent years, as emerging economies in the latter region are expanding their refining capacity, in anticipation of the growth in their demand for oil.

Asia Pacific markets

This region has been something of an oddity in terms of pricing benchmarks. As noted earlier, there are several regional crude grades available, emanating primarily from Indonesia and Malaysia, but also from Australia, China and Vietnam. The region is largely dependent on imports, predominantly from the Middle East, but also from West Africa and even the North Sea. As a result, there are several crude grades traded in the region, some of which were discussed above. In addition to these grades, three regional indices have also been developed over the years: APPI, ICP and JCC.

The Asian Petroleum Price Index (APPI) is assessed twice weekly by a panel of traders, producers and refiners. It is based on a basket of crude oils traded in the Asia Pacific region, including imported and regionally produced ones. The Indonesian Crude Price index is assessed once a month by Pertamina, the Indonesian state oil company and is effectively an Official Sale Price (OSP) for the various crude oils it produces, led by Minas.

All of these price indices have a common fundamental characteristic – they are reactive. This means that they are calculated, with some time lag, after the prices of the individual crude oils have been set. The result is that they are not really benchmark prices, they are rather market activity indices, reflecting the level of prices based on recent transactions. Behind these prices one can ultimately trace the effects of the three key benchmarks, especially Brent and Dubai.

Conclusion

Oil continues to be right at the heart of world energy, although its role has changed significantly over the years. The history of the oil industry is, of course, fascinating, but knowledge of it does not offer just pleasure; it also helps build an understanding of the economics of the industry. The previous chapter focused on the economics of energy production and consumption; this chapter concentrated on the particulars of crude oil supply, as well as oil pricing. After the oil price collapse of the mid-1980s, the world witnessed a notable switch to open market pricing. This led to the emergence of three key benchmarks Brent, WTI and Dubai. Although the combined output of these crude oil does not command an important part of world oil production or trade, their prices are instrumental in the trading of the many different types of crude oil around the world and also act as indispensable reference prices for the industry at large, including derivative paper contracts (futures, options, swaps and so on), royalty/taxation and production sharing contracts. They even influence the prices of other energy commodities, such as natural gas, as will be demonstrated.

The next chapter deals with the downstream part of the oil industry, focusing on petroleum refining and trade in oil products.

References

Adelman, M.A. (2002). World Oil Production and Prices 1947-2000. Quarterly Review of Economics & Finance, 42, 169 - 191.

Alhajji, A.F. & Huettner, D. (2000). OPEC and World Crude Oil Markets from 1973 to 1994: Cartel, Oligopoly, or Competitive? Energy Journal, 21, 31-59.

Bentzen, J. (2007). Does OPEC influence crude oil prices? Testing for co-movements and causality between regional crude oil prices. Applied Economics, 39, 1375 - 1385.

Fattouh, B. (2011). An Anatomy of the Crude Oil Pricing System. Working paper WPM40. Oxford Institute of Energy Studies.

_____ (2012). The Dubai Benchmark and its Role in the International Oil Pricing System. Oxford Institute of Energy Studies. Accessed on line at http://www.oxfordenergy.org/wpcms/wp-content/uploads/2012/03/The-Dubai-Benchmark-and-its-Role-in-the-International-Pricing-System.pdf.

Gülen, S.G. (1996). Is OPEC a Cartel? Evidence from Cointegration and Causality Tests. Energy Journal, 17, 43-57.

Horan, S.M., Peterson, J.H. & Mahar, J. (2004). Implied Volatility of Oil Futures Options Surrounding OPEC Meetings. Energy Journal, 25, 103-125.

IEA (n.d.). Oil Market Report. https://www.iea.org/topics/oil-market-report

Kaufmann, R.K. et al. (2004). Does OPEC Matter? An Econometric Analysis of Oil Prices. Energy Journal, 25, 67-90.

Kohl, W.L. (2002). OPEC Behavior, 1998-2001. Quarterly Review of Economics & Finance, 42, 209-233.

Lin, S.X. & Tamvakis, M. (2010). OPEC announcements and their effects on crude oil prices. Energy Policy, 38, 1010 - 1016.

Loderer, C. (1985). A Test of the OPEC Cartel Hypothesis: 1974-1983. Journal of Finance, 40, 991-1006.

Marcel, V. (2006). Oil Titans: National Oil Companies in the Middle East. Chatham House/Brookings. London.

Raymond, M.S. & Leffler, W.L. (2005). Oil and Gas Production in Nontechnical Language. PennWell Books. Tulsa, OK.

Smil, V. (2017). Oil: A Beginner's Guide. Oneworld PublicationsSmil, La Vergne.

Venditti, P. & Parker, S. (2024). The World's Biggest Oil Producers in 2023. Visual Capitalist. https://www.visualcapitalist.com/the-worlds-biggest-oil-producers-in-2023/

Wirl, F. & Kujundzic, A. (2004). The Impact of OPEC Conference Outcomes on World Oil Prices 1984-2001. Energy Journal, 25, 45-62.

Yergin, D. (1993). The Prize: The Epic Quest for Oil, Money and Power. Simon & Schuster Ltd. New York.

_____ (2011). The quest: Energy, security and the remaking of the modern world. Allen Lane.