THE GLOBAL OIL MARKET | A REVIEW PAPER

Prepared by

for

24 November 2016

The Global Oil Market | A Review Paper Cape Otway Associates

The IEA secretariat has noted that ‘Oil markets have changed enormously since the first oil shock of 1973-74.’ This paper addresses the question: How have the oil market and institutions evolved since the 1970s and what new challenges will they face in the coming decades?

This paper has been prepared by Cape Otway Associates in response to a request from the Australian Government on the need for a comprehensive review of the global oil market, its historical development—with a particular focus on the past 45 years since the early 1970s—its current status and the outlook for its future evolution.

The paper is intended to be a public document and aims to present a factual view of the present global oil market, and of its historical development. Forward-looking views are presented in terms of the continuation of observed underlying trends that display strong momentum—economic development and demographics that are driving the shift of oil demand from west to east are a good example—as well as turning points, historical patterns, the role of market, economic, technological and policy forces, new developments and areas of uncertainty.

While the paper aims to be fact-based, in places, the implications or challenges arising from these shifts, including for Australia, for other IEA member countries and for the IEA and other international institutions are touched upon. Any views expressed in the paper are those of the author and should not be construed as representing the views of the Department of the Environment and Energy, nor of the Australian Government.

Cape Otway Associates thanks the many careful reviewers for their feedback, corrections and comments on earlier drafts. Any remaining errors are those of the author.

Cape Otway Associates The Global Oil Market | A Review Paper i

Oil markets have changed enormously since the first oil shock of 1973-74.

—International Energy Agency, 2014i

Executive Summary

This paper addresses the question: How have the oil market and institutions evolved since the 1970s and what new challenges will they face in the coming decades?

To answer this question, the paper takes a ‘generational’ perspective: looking back over the 70 years since World War 2 and looking forward at trends that are likely to unfold over the 35 years to 2050. Major trends of global significance evolve over such timeframes, providing context for assessment of major changes in oil market and institutions.

The paper explores the ‘JAM’ thesis that oil is Just Another Market, the antithesis that oil is an exception, and the synthesis that oil is indeed special, but that market approaches work best. The paper explores the long-run implications for: oil importers including OECD countries and key countries in Asia, for oil exporters and their national oil companies (NOCs), for international oil companies (IOCs), and for international institutions.

The paper also explores the historical evolution and development of the market from various perspectives and in greater depth than is possible from looking only at prices. While prices are important and crystalise a lot of information, the paper drills down to explore and explain the significant drivers of prices. The drivers are not limited to the economic fundamentals of supply and demand, but also cover significant factors that have either directly or indirectly affected those fundamentals. These factors include: affordability; the reversal from the fear of imminent depletion to concern about the environmental implications of abundant oil; the Energy Policy Trilemma and the inevitability of difficult policy trade-offs; the key role of expectations; the influence of policy priorities; and the role of geopolitics.

The key findings of the paper are grouped under three observations:

1. Looking back, the oil market has indeed changed enormously since the first oil crisis.

2. Looking forward, long-run indicators suggest oil is on the threshold of a new pricing era.

3. Market-based policy works best to ensure affordable, accessible and secure supply of oil.

1. Looking back, the oil market has indeed changed enormously since the first oil crisis

Modern oil markets are among the largest and most efficient markets in the world,1 delivering increased economy-wide affordability and enabling sophisticated financial risk management. The risk of disruption has been reduced and economies are more resilient to oil supply disruptions. There is strong evidence that demand growth changes, not supply disruptions, largely explain oil price shocks.

Physical and financial oil markets are now large, deep and liquid

In 1975, 55 million barrels per day (Mbpd) were consumed globally, of which 29 Mbpd were internationally traded. In 2015, the world consumed 95 Mbpd of crude oil and condensates. About half of this was traded internationally, and the balance produced and consumed within countries (Figure 21).

In London and New York, the total daily traded volume of oil futures contracts is about 45 million ‘paper barrels’: equivalent to the world’s daily export and import of physical ‘wet barrels’ (Figure 1).2 This reveals the size of the financial oil market is comparable to the physical traded oil market.

1 Kristoufeka and Vosvrda (2013) ‘Commodity futures and market efficiency,’ Energy Economics, found that energy futures were the

most efficient among types of commodity markets and that heating oil, closely followed by WTI crude oil had the highest market efficiency of 25 commodity futures studied across various groups—metals, energies, softs, grains and other agricultural commodities.

2 Contracts for future deliveries of Brent and West Texas Intermediate (WTI) benchmark crude oils are traded on the Inter-

Continental Exchange (ICE) in London and on the New York Mercantile Exchange (MYMEX), respectively.

ii The Global Oil Market | A Review Paper Cape Otway Associates

In 1973 there were no government emergency stocks and no financial oil risk management tools

In 1973, there was no large, government-mandated system of emergency stocks.3 Neither daily spot price trading of benchmark crude oils, nor financial oil markets existed in 1973. The modern oil market strongly interlinks the financial and physical markets, as shown in Figure 22. The IEA emergency reserves system exists separately from the markets, but can affect markets.

Financial markets that manage oil risk are now larger than official emergency response systems

Financial instruments first established in the 1980s now provide sophisticated and responsive real-time risk management tools for the oil market, harnessing the commercial incentives faced by thousands of sophisticated and well-informed decision-makers in hundreds of companies and financial institutions. Participants are free to use the market to manage their desired risk exposure. Financial markets distill an enormous flow of market information and market expectations into a continuous stream of prices, enabling oil producers, consumers, traders and financial intermediaries to hedge their risks, or to take on risk, thereby realising opportunities for profit (or loss). The ‘open interest’ in futures contracts alone is equivalent to about 90 days of international physical oil trade.4

In the 1970s there was an oil industry but ‘the oil market’ as we know it today did not yet exist

Not only was there no financial futures market or options market in the 1970s, but oil production was regulated and prices were fixed in nominal dollar terms for extended periods. Forward contract prices were ‘posted’ after agreement between national and international oil companies. There was no spot market referenced to benchmark prices. The Bretton Woods system of dollar-gold exchangeability and fixed currency exchange rates was in place until August 1971. Today’s deep and liquid markets in currencies, commodities and financial derivatives, were developed during the 1970s and 1980s.

The 1973-74 ‘oil shock’ only ranks ninth among the list of historical oil supply disruptions

The ‘first oil shock’ in 1973-74—an embargo announced by the Organisation of Petroleum Exporting Countries (OPEC)—resulted in the disruption of 1.6 Mbpd for six months (see Figure 50).5 At the time, IEA countries’ oil imports totaled 27.4 Mbpd. There have been eight oil supply disruptions of larger magnitude than the 1973-74 Arab Oil Embargo: two earlier and six since.6 Only two of those disruptions lasted for longer: the 4.6 Mbpd year-long disruption following Iraq’s retreat from Kuwait in 1990 and the 3.3 Mbpd OPEC cut in 1999. There have been five other supply disruptions of longer duration, but smaller magnitude than 1973-74. Multiplying the magnitude by the duration of supply disruptions, the 1973-74 event still only ranks ninth among the list of historical events. Yet the repercussions of this shock were large, due to policy settings and policy responses that exacerbated its impacts.

The oil shocks of the 1970s were misdiagnosed and misunderstood at the time

Economic research since 2000 has revealed that supply disruptions were the catalyst but not the cause of the 1970s oil shocks.7 The 1970s oil shocks were symptoms of deeper economic problems. Real prices did not reflect the fundamentals of supply and demand, due to inadequacies in the mechanisms of price formation and price discovery. Exogenous oil supply disruptions explain no more than 20 per cent of the observed increase in the real price of oil in 1973-74; shifts in the underlying demand for oil explain at least 80 per cent of the price changes. Speculative inventory demand (‘panic buying’) is observable before and during a number of oil crises, and can magnify the shock, but is not the underlying cause. With the benefit of these recent insights, it is perhaps not surprising that misdiagnosis of the problem gave rise to some unsuccessful policy responses.

3 The IEA emergency reserve system was established in 1974 and in November 1976, the IEA Governing Board agreed to increase emergency stocks from 60 to 90 days of net imports by the end of 1979.

4 The 90 days does not include other derivatives contracts, such as put and call options, spreads and swap contracts. Most oil

derivatives positions (futures and options) are closed out via cash settlement before physical delivery.

5 The first part shows the disruptions in absolute volume terms; the second part as a percentage of OECD imports.

6 The two larger disruptions before 1973 were the 1956 Suez War and the 1967 Six Day War. The six larger disruptions since

1973 were the 1978 Iranian Revolution and the 1980 outbreak of the Iran-Iraq War (together called the second oil shock), the 1990 Iraq-Kuwait War, the 1999 OPEC production cuts, the 2002 Venezuelan oil strike and the 2003 Iraq War.

7 Kilian L (2014) ‘Oil Price Shocks: Causes and Consequences,’ Annual Review of Resource Economics

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Government efforts to manage the oil market by emergency rationing in the 1970s ultimately failed

The 1973-74 oil shock caused large reverberations for many reasons, including but not limited to: OECD countries’ large and growing import dependence on OPEC and Middle East producers; the absence of market-based trading arrangements; an inflexible pricing regime that had become severely disconnected from economic fundamentals of supply and demand; the breakdown of the global monetary system and rising inflation.

Demand growth and oil import dependency had been growing rapidly, leading to a ‘break point’ in 1973 (Figure 40). Again, the Yom Kippur War and Arab Oil Embargo were the catalyst, but not the underlying cause of the crisis. The IEA’s official history observes:

The vulnerability of the industrial countries to serious oil supply disruptions and to price shocks occurring largely outside of their control was not a sudden development, although the awareness of the associated risk did appear suddenly to many energy policy makers only late in 1973 when the crisis began. The combination of situations which created the crisis evolved over a number of years before the crisis occurred.8

With the benefit of hindsight, many government policy responses to the 1973-74 oil shock failed and were later abandoned. Foremost among unsuccessful policies were price, production, allocation (rationing) and marketing controls.9 Another key factor, United States dollar inflation, was eventually controlled.

Some other policies originally developed in response to the 1970s oil shocks have been retained

Policies that have been maintained since the 1970s oil shocks, in parallel with the successful approach of allowing the market to work include: encouragement of improved energy efficiency, fuel switching and exploration and production of alternative sources of oil supply. Policy development by national and international public agencies today is informed by data, modelling, analysis and projections, benefiting greatly from the work of the IEA. Publication of data, projections and scenarios by oil companies contributes further. These responses have been complemented by co-operation between the governments of oil-importing countries, notably through the IEA, including the Collective Emergency Response Mechanism (CERM); and data sharing and dialogue between oil-exporting and oil-importing countries. Figure 51 shows the IEA’s Emergency Response System. The CERM is used to determining whether a collective action and drawdown of emergency stocks is required.

Oil supply disruptions occur continually and are mostly managed well by the market

It is rare for all of the world’s oil production capacity to be available at any given time. Mot disruptions are relatively small in magnitude and short-lived. Figure 49 neatly illustrates why the two oil price shocks of 1973-74 and 1979-80 were defining events in the world oil market: they were by far the largest oil price shocks of modern times. The desire to avoid a repeat of those events has influenced thinking about oil and security of supply since and continues to do so. The success of markets in managing oil supply disruptions is also apparent from a comparison of Figure 50 with Figure 49: far smaller price shocks followed larger supply disruptions.

Allowing market forces to rebalance supply and demand through price signals has been foremost among the more successful policy responses. The market responses to the 2004-08 and the 2010-14 oil demand surges and price increases were orderly and the adverse economic impacts smaller than after the 1970s shocks. Likewise, the market response to the price collapses of 2008-09 and from late 2014 have been unexceptional, albeit challenging for oil-exporting countries and oil-producing companies. Strong parallels with the oil market’s rebalancing phase from 1983 to 2003 have emerged following the price collapse of late 2014. Many small oil supply disruptions from 2011-15 add up to between 2 and 3 Mbpd of continuous unavailability. That is comparable in scale and longer in duration than the occasional historical disruptions. The oil market is working as it should.

8 Richard Scott (1995) IEA—The First 20 Years: The History of the International Energy Agency 1974-1994; Volume Two: Major Policies

and Actions, IEA and OECD, Paris, p.25.

9 The US Emergency Petroleum Allocation Act (EPAA) was drafted, debated, passed and signed into law 42 days after the Arab Oil Embargo was announced. It authorised price, production, allocation, marketing and export controls. Price and allocation controls were repealed by Presidential Executive Order in January 1981. The US crude oil export ban was lifted in December 2015.

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The market is far more transparent than in the 1970s and supply is better at rebalancing

A greater quantity and higher quality of oil market data is available from official agencies, from market prices and via commercial subscriptions, little of which existed in the 1970s. The oil industry uses that market information and contributes to balancing the crude oil market through:

movement of oil into or out of storage through commercial inventory management

management of spare capacity to increase or decrease production (mainly in Saudi Arabia)

investment in new unconventional light tight oil (shale oil) supply

investment in new conventional oil supply

These market responses each have their own characteristics, as shown in Figure 58. Release of emergency stocks is a non-market emergency response mechanism available to governments. For IEA member countries it is managed under the CERM of the International Energy Program (IEP, the treaty governing the IEA). IEA ‘collective action’ has only been initiated on three occasions: the 1991 Gulf War, in 2005 after Hurricanes Katrina and Rita in the United States, and during the 2011 Libyan Revolution. Other larger, and longer supply disruptions have not occasioned IEA collective action.

The risk of intentional or ‘strategic’ supply disruption by oil exporting countries is now much lower

The greatest risk of intentional oil supply disruption arises in countries with the most to gain and the least to lose: those with large oil exports but where oil revenues represent a small share of total export revenues and of the government budget. As Figure 11 shows, there are no countries in that category. Large exporting countries are mutually interdependent with their oil-importing trade partners, due to their reliance on oil revenues.

Just as OECD countries have the benefit of policy lessons from failed responses to the 1970s oil crises, OPEC countries have also been able to draw lessons from their subsequent experience. One such lesson is that when oil demand goes elsewhere in response to large oil price increases—particularly as a result of intentional withholding of supply by producers—not all of that demand returns in response to later price decreases. It is easy to lose market share and difficult to regain it.

That applies to exporters’ share of the oil market, and also to the market share of oil within energy markets more broadly. The response to the 1970s crises delivered dramatic short-term benefits to producers and exporters in the form of much higher prices providing greatly increased revenues on somewhat smaller volumes. Consumers and importers were not able to respond fully ‘overnight.’

However, by the early- to mid-1980s, the reduced and declining oil share of primary energy, and the reduced and declining OPEC share of the oil market were both clear. In 1973, re-alignment of demand and supply, and prices reflecting industry fundamentals were clearly needed. Nevertheless, OPEC countries, especially Saudi Arabia, have not forgotten the fall in both oil prices and their share of the oil export market in the 1980s and the persistence of low oil prices throughout the 1990s.

Saudi Arabia’s spare capacity monopoly and OPEC’s oil export dominance give only limited power

Although the United States had been a net oil importer since 1944, in March 1971 it had no remaining spare capacity and therefore, as a result, control of oil prices transferred to Saudi Arabia, which held the only flexible spare oil production capacity. In that year, OPEC accounted for 82 per cent of world oil exports, increasing to 85 per cent by 1974. OPEC as a whole has a very low reserves-to-production (R/P) ratio of 26 years, but the Middle East still dominates proven oil reserves and also has an R/P ratio of 100 years, which is the highest of any region worldwide. Oil production is only moderately concentrated in OPEC, but oil exports remain highly concentrated in OPEC.

OPEC’s share of world oil exports converged on 60 per cent in the 1990s. That collective market share confers oligopoly market power on the OPEC producers, according to the usual measure of market concentration. In addition, Saudi Arabia retains its near-monopoly on flexible spare oil production capacity. And yet OPEC has only been in a position to sustain high prices for two periods since 1973: from 1973 to 1983, and from 2004 to 2014. OPEC’s attempts to manage price in the 1970s and 1980s by continuing the old system of ‘posted prices’ through the 1970s and then trying netback prices in the 1980s were abandoned. The oil market of today emerged from the benchmark-pricing regime in the 1980s. From 2004 to 2014, OPEC was unable to restrain prices from rising to levels that risked a repeat of the 1980s and 1990s low price experience.

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Oil has a smaller share of the fuel mix in the global economy than in the 1970s

The share of oil in primary energy consumption varies widely between countries (Figure 48), but the range has narrowed since the 1970s oil shocks. In 1973, oil supplied 49 per cent of the world’s primary energy requirements. By 2015, oil’s share had declined to 33 per cent, as shown in Figure 47. The reduction in the oil share of primary energy reduces the sensitivity of oil importing countries to oil supply problems and the exposure of the world economy to oil supply or price shocks. In the 1970s many countries could not meet their electricity needs without oil. Today, most countries operate their electricity grids without any oil. However, oil continues to have a near-monopoly in the transport sector worldwide.

In 2015, oil at the same real price levels as 1975 is more affordable relative to GDP

In 1965, the global expenditure on crude oil was just one per cent of gross world product (GWP). In the five decades since, crude oil expenditure has ranged from one to eight per cent of GWP. Figure 67 shows the annual data. During the recent double price peaks in 2008 and 2011-12, crude oil expenditure was about five per cent of GWP. So, referring back to Figure 1, while real oil price levels in recent years were similar to the price levels in 1979, expenditure on oil as a share of GWP was comparable to the period 1974-78 and reached only about half the level of the 1979 peak.

The improvement in economy-wide oil affordability is remarkable, considering the extent to which industry revenues have grown, and in view of real price levels. In 1965, the global crude oil was a $150 billion industry: 30 Mbpd, at an average price of $13.50 /bbl, in 2015 US dollars. Half a century later, in 2014, the industry was a $3.3 trillion industry—22 times as large. Consumption had increased three-fold to 92 Mbpd. At almost $100/bbl, prices were at seven times the level of a half-century earlier. Then in 2015 spot prices collapsed to the mid-20s, just twice the 1965 price level after adjusting for inflation. Market prices multiplied by global consumption of 95 Mbpd was $1.8 trillion—slightly less than $1.9 trillion in the 2009 depths of the Global Financial Crisis and less than half of the $3.7 to $3.8 trillion per year from 2011-13.

2. Looking forward, long-run indicators suggest oil is on the threshold of a new pricing era

The major theme of the new era is the eastward shift in energy demand, oil demand and oil imports. OECD countries’ share of world oil imports is falling rapidly. China already imports more oil than the United States, and is already denominating some oil trade in Renminbi, not dollars. The greatest uncertainty is in discerning what factors will most influence oil supply economics.

Strong underlying trends are expected to continue to make oil more affordable

Notwithstanding the 2014-15 oil price collapse, long run marginal costs of production tend to increase gradually over time as the lowest cost reserves are depleted. The trend is moderated somewhat by technological advances, as the market grows. However, the real economy has grown at a faster rate than oil consumption for more than three decades, due to improved energy efficiency, increased energy productivity and oil’s declining share of primary energy. Affordability will continue to fluctuate widely, but if the underlying trends continue as is expected, then oil will continue to become more affordable over time, even if inflation-adjusted prices increase in the long run.

The shale revolution is expected to continue to ease global pressures on new oil supply and prices

The shale gas and shale oil revolution in the United States is part of the ‘Great Energy Rebalancing’ currently underway. The technical revolution is an example of a ‘magic bullet’ in the rebalancing phase of the ‘energy evolution cycle’ (Figure 39) that begins with growth and dependency, followed by pressure buildup, leading to a ‘break point.’ Porter’s ‘Five Forces’ continue to play their role in the market, as illustrated in Figure 37. Referring back to Figure 40 shows that the process played out chaotically in the 1970s, with significant demand destruction, but has so far played out in a more orderly way in the 2000s, thanks to the greater role and maturity of the market.

Until recently, shale oil was considered uneconomic and was not even included on the long-term oil-supply cost curve compiled by the IEA in 2008 (Figure 36).10 The updated curve published in 2013 (Figure 42)

10 Note that ‘oil shales’ in the chart are not the same as ‘shale oil.’ The former involve the use of heat such as steam retort methods,

to extract oil. In contrast, ‘shale oil’ or ‘light tight oil’ involves horizontal drilling and hydro-fracking the source rock to stimulate the oil to flow out of the wells.

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includes light tight oil (shale oil), at a cost range of between $50 and $100 per barrel. The lowest cost shale oil resources were infra-marginal during the recent high oil price period, and are now marginal. The high cost shale oil resources were marginal during the recent high oil price period and are currently non-commercial.

Shale oil has had a major effect on oil markets and oil prices over the medium-term. Nevertheless, significant uncertainty remains: it is not yet clear whether shale oil, or other factors will have the most significant long-term influence on the economics of oil supply.

Net oil exports from the United States require special conditions to prevail

In recent years there has been a great deal of speculation about the prospects for the United States to become ‘energy independent.’ In the reference case of its most recent outlook, the United States EIA is not projecting United States oil production to exceed United States oil consumption (Singer, 2016). It is projecting a small surplus (implying exports) from about 2020 growing to about 2 Mbpd in its high price case. That scenario has oil prices in 2015 dollars exceeding $150/bbl in the early 2020s and continuing to climb to $225/bbl by 2040.

In the high oil and gas resource and technology case (in which prices recover to about $75/bbl by 2020 and then rise steadily to just over $100/bbl by 2040) the EIA has net exports of oil by the United States beginning in the early 2020s and increasing to 5 to 6 Mbpd by 2040. The low price case and the low oil and gas resource and technology case call for oil imports increasing again from about 5 Mbpd to about 7 to 8 Mbpd by 2040. In any case, the main trend will continue to be the increasing market demand for oil imports from China, India, ASEAN and the developing world in general.

Long-term indicators suggest the oil market is on the cusp of entering a new era

Evidence suggests the risk to OPEC from a sustained period of high prices has been realised: a new category of supply has been stimulated in the form of North American light tight oil. In late 2014 and early 2015, Saudi Arabia and other OPEC producers found themselves in the position of maximising production and competing to defend market share, driving down oil prices in the process. This has echoes of the two-decade low price era of the 1980s and 1990s. OPEC is not dead; it has just been forced to switch from defending price to defending market share for the foreseeable future.

Concerns about both high oil prices and security of supply that arose between 2004 and 2014 have since been moderated by the response of the market. Price signals are helping supply and demand to rebalance. Economies have so far coped well with an oil price cycle on the same scale as the 1970s oil shocks, accompanied by the most severe financial crisis and economic recession since the 1930s.

The recent oil price peaks actually have more in common with the 1970s than is commonly thought. High growth in oil import demand was a major factor behind the 1970s oil shocks, and high growth in Chinese oil demand was a significant factor in the 2000s. This is part of a deeper trend in which competition for oil imports is growing as oil demand growth shifts relentlessly eastwards, associated with the economic rise of developing Asia.

‘The world of rich nations is just beginning to realise that it no longer dominates energy markets’ 11

The global share of oil imports by Europe, the United States and Japan is falling dramatically, therefore so is the IEA countries’ collective share of world oil imports. At the same time, the global share of oil imports to China, India and the rest of the world is increasing. Oil demand is shifting inexorably to the Indo-Pacific and will no longer be Atlantic-centric and dominated by OECD countries (Figure 69). This is the major theme of the new era, and one of the clearest strong trends for any oil and energy outlook.

The reasons for this trend are: flat to slightly declining demand in OECD countries; steadily increasing demand in emerging Asian economies; and the recent increase in North American oil production. At the same time, domestic oil production-and-consumption in Saudi Arabia and the rest of the Middle East is now larger than domestic oil production-and-consumption in the United States and China combined (Figure 4). Domestic energy efficiency and fuel switching from oil to gas, coal, nuclear or renewable energy would allow Saudi Arabia to increase oil exports without increasing oil production.

11 Carlos Pascual (2015) The New Geopolitics of Energy, Columbia University School of International and Public Affairs (SIPA)

Center on Global Energy Policy (CGEP), New York, September

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The changes in the oil market and the trends underway have various implications for oil importers including key countries in Asia, oil exporters and their NOCs, IOCs and international institutions. OECD countries are in a far better position in 2015 than they were in 1975, which is a testament to the collaborative work under the umbrella of the IEA. At the same time, inexorable eastward shift in oil demand, and in oil imports accelerated by the United States domestic light tight oil production means that the IEA approach to energy security can no longer be OECD-centric. Nor can it focus on the Euro-Atlantic region plus Japan, as was the case from 1974 to 2004. New thinking will likely be required to ensure that international institutions are well suited to the challenges of the 21st century, and not constrained by approaches that were crafted in response to the crises of the 1970s.

Oil has a special place among commodities, but drawing from lessons from history and the experience accumulated from the 1970s to the present confirms the wisdom of using a market-based policy approach for oil in particular and for energy in general to meet future challenges.

3. Market-based policy works best to ensure affordable, accessible and secure supply of oil

The enormous changes have been for the better and confirm the core role of the market

The changes in oil markets since the first oil shock of 1973-74 have been both profound and positive: favourable for importing countries and consumers, and constructive for exporting countries and investors. It is difficult to think of any way in which oil markets today are not better than in 1973-74. The market has proven well able to cope with supply disruptions. Emergency government intervention in the market has been very rare: there have been only three IEA collective actions. High quality, detailed timely data on supply and demand, costs and prices, reserves and technology is widely available; and markets now send better price signals than oil producers and regulators could manage in the 1970s. Government and company representatives from exporting and importing countries meet regularly to discuss topics of mutual concern, and oil exporters have not tactically or strategically disrupted oil supply since 1974. Supply and demand balance more readily; and flexible spare capacity in Saudi Arabia does not need to swing to the same extremes to rebalance the market. Vehicle technology has evolved continuously, and oil is now used more efficiently and cleanly. Economies are less exposed to changes in oil prices and oil is also more affordable than ever before, even at times when real prices have been higher than in the 1970s. Sophisticated risk management via financial markets interfaces seamlessly with physical markets. Capital is directed to investments in new supply around the world when and where it is needed. Technology continues to evolve and breakthroughs reinvigorate the industry from time to time. Shale oil—a new source of supply with a much shorter lag time from investment to production—recently changed the market. Continental pipeline networks and a global tanker fleet match crude oil with refinery requirements and products with market demand globally.

Policies that leverage the markets’ natural strengths have delivered surprising benefits

Oil and the global macro economy are deeply interwoven, as are markets and economy-energy-environment policy settings. This was recognised in 1993 by the IEA Ministers: their Communiqué that year stated that they ‘…believe that global economic development, energy security and environmental protection will be enhanced if all nations of the world subscribe to the goals which the IEA countries share.’ The ‘Three Es’ of energy policy that in 1993 provided the basis for the IEA’s Shared Goals are reflected in the Energy Policy Trilemma, the challenge whereby governments try to maximise security of supply, minimise economic costs and minimise environmental impacts.

Since 1993 the IEA has also emphasised free market issues, ‘…reflected in the IEA’s work on deregulation, reduced government interventions in markets (particularly with respect to price), privatization, greater competition, and increased productivity of undertakings in the energy sector.’12

Physical and financial oil markets have evolved to become the world’s largest and most efficient international commodity market. This outcome is made more remarkable by the fact that security of supply has also improved as a result of financial risk management becoming seamlessly integrated with short-run price discovery, commercial management of inventories and long-run investment decision-making.

12 Scott R (1995) IEA—The First 20 Years: The History of the International Energy Agency 1974-1994; Volume Two: Major Policies and

Actions, IEA and OECD, Paris, p224.

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Valuing oil security and the contribution of market risk management

A recent study that sought to quantify the value of oil security or, more specifically, the value of the IEA emergency stocks and the economic benefits of the IEA emergency reserve system, obtained very high estimates of net benefits.13 The results reflect the historically high oil price level that prevailed in 2011, along with several other economic and modelling assumptions. Oil supply disruption probabilities underpin the work, and are based on expert panel estimates of the magnitude, duration and expected frequency of various events in an influence diagram.

An initial comparison of the probability distributions with the data on historical disruptions (in Figure 50) suggests that the 2015 expert review process appears to have generated materially higher probabilities than have been observed historically since 1951. Conversely, the probability of ‘black swan events’: very rare, large-magnitude, long-duration disruption events may have been under-estimated relative to what is implied by the historical data. However, considerable further in-depth research and analysis would be required to confirm (or reject) that hypothesis.

Comparisons and analogies with banking reserves may yield insights for oil security

Banking reserves and emergency oil reserves or strategic stockholdings are not identical, but there are some parallels between them, in the sense that they are both retained, at a financial cost, as contingencies against unforeseen adverse events. Furthermore, speculative inventory demand for oil during a crisis is analogous to behaviour observed in financial panic events known as ‘bank runs.’

The system of central banks is an integral part of national banking systems, of the worldwide banking sector, and of the global financial and monetary system. In contrast, the system of emergency oil reserves and strategic stockholdings exists in parallel with, but separately from financial oil markets, with no defined relationship or linkages between the two.

The situation reflects the fact that oil stocks were designed and established in the 1970s to respond to oil supply disruptions at a time when modern physical and financial oil markets did not exist. Since they were created in the late 1980s, financial markets for oil have grown to be larger than the system of emergency reserves managed by governments, which was previously the only oil risk management system in existence.

More recently, some countries outside the IEA’s coordinated system, most notably China, have established their own strategic petroleum reserves. China’s banking and financial systems are gradually becoming more integrated with global banking and financial systems. Long run coordination with China on oil reserves may be mutually beneficial and is worth exploring.

Avenues to build on achievements to date for policy development and modernisation

Oil and the global macro economy are deeply interwoven, as are markets and economy-energy-environment (‘3E’) policy settings. The IEA Ministers’ Communiqué in 1993 stated that they ‘believe that global economic development, energy security and environmental protection will be enhanced if all nations of the world subscribe to the goals which the IEA countries share.’ These ‘Three Es’ of energy policy provide the base for the IEA Shared Goals.14

More than 20 years later, although priorities and constraints change and also vary between countries, affordability, security and environmental sustainability are still the three major goals of energy policy throughout the world. Reducing carbon dioxide beyond the commitments in the 2015 Paris Accord, presents significant policy challenges. The experience gained during the third and fourth decades of the IEA’s history (1994-2014) shows that economic growth and the free market have not only delivered increased affordability, but oil security has also improved. This provides encouragement that the free market principles set out in the IEA’s Shared Goals of 1993 can also provide a solid foundation for the goals of the IEA Modernisation Programme, as announced in 2015.15

13 Stelter J and Nishida Y (2013) Focus on Energy Security, IEA insight series, Paris

14 Scott R (1995) IEA—The First 20 Years: The History of the International Energy Agency 1974-1994; Volume Two: Major Policies and

Actions, IEA and OECD, Paris, p224.

15 Moniz E J (2015), Summary of the Chair, IEA Ministerial Meeting, 17-18 November 2015

https://www.iea.org/media/news/2015/press/IEAMinisterialChairsSummary.pdf

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There are a number of avenues for cooperative research, policy development and collaboration between and beyond IEA member countries. A deeper understanding of the historical relationship between the magnitude, duration and frequency of oil supply disruptions would be very valuable for many stakeholders. The contribution of that oil markets have made to strengthen and broaden oil and energy security since the 1980s could be better understood. Research could include quantifying the extent to which risk management by the market has relieved the pressure on official oil security emergency response systems. The global economic benefit resulting from the continual operation of risk management through the financial markets in oil futures and derivatives has not yet been studied, to the authors’ knowledge. Furthermore, it would be beneficial to review how the emergency oil reserves system could be modernised to complement and work seamlessly with the existing large and sophisticated financial oil markets.

Conclusions

The key conclusions of the paper are as follows:

OECD countries’ share of global oil imports is falling as their demand plateaus or declines and as oil demand grows in non-OECD countries.

The reduction in United States oil imports due to domestic light tight oil production has further accelerated the eastward shift in oil imports.

Most of the changes in the oil market since the early- to mid-1970s have been beneficial.

The oil shocks of the 1970s were misdiagnosed and misunderstood at the time.

Most oil supply disruptions are small and brief in duration.

Some of the policy responses in the 1970s worked against the market and hindered the effectiveness and efficiency of the market in rebalancing supply and demand.

Notwithstanding the ongoing possibility of major disruptions arising from major geopolitical events, the risk of intentional or ‘strategic’ supply disruption by oil exporting countries is now much lower than in the past, because oil-exporting countries have learned from the long-term adverse effects of disrupting supply.

The transport sector continues to be very heavily dependent on oil.

The contemporary oil market is also far more transparent and supply is better at rebalancing than in the 1970s.

Initial indications are that the United States shale oil revolution has resulted in an oil supply curve that may be able to respond more rapidly and more smoothly to price changes.

The challenge for policy-makers, and for companies and investors, attempting to resolve the Energy Policy Trilemma, are arguably greater today than it has ever been.

The physical and financial oil markets have evolved to become the world’s largest and most efficient international commodity market.

The lessons learned from the responses to the oil crises of the 1970s show the value of:

Allowing markets to work, prices to find their market clearing level, prices to signal the need for new supply (or not, as the case may be) and investment to respond to price signals

Increased information on supply and demand for market participants and policy makers

Development of financial markets to provide forward price signals and manage risk, and

Increased dialogue between producer-exporter nations and importer-consumer nations.

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The Global Oil Market | a review paper

Executive Summary i

Abbreviations used in this paper xvi

Glossary of terms used in this paper xvii

Chapter 1. Overview and introduction 1

1.1. Key questions prompted by the profound generational changes in oil markets ............ 1

1.2. Key themes ................................................................................................................................... 2 1.2.1. The evolution and development of the oil market .................................................................................... 2 1.2.2. A framework to make sense of the historical data and to guide the outlook ...................................... 3 1.2.3. Alternative perspectives, long-term data, patterns and historical parallels ....................................... 4 1.2.4. The geographic balance of supply and demand ......................................................................................... 8 1.2.5. Changes in the geographic shares of oil imports ....................................................................................... 9 1.2.6. Changes in the geographic shares of oil exports ..................................................................................... 10 1.2.7. Oil import dependence and independence ................................................................................................. 11 1.2.8. Australia’s situation has similarities and differences with the world as a whole ............................. 12 1.2.9. Oil export revenues and mutual inter-dependence between exporters and importers .................. 15 1.2.10. The importance of viewing the oil market from multiple perspectives ........................................... 16 1.2.11. The value of recalling historical context and lessons for the future ................................................ 17

Chapter 2. The Current State of the Oil Market 20

2.1. Key characteristics of the oil market today ......................................................................... 20 2.1.1. Prospects, resources, exploration and reserves........................................................................................ 20 2.1.2. Exploration and production technology, costs and the price cycle .................................................... 22 2.1.3. Relationships between prices and costs and between oil and other commodity prices ................. 24 2.1.4. Risk, financing and investment .................................................................................................................... 26 2.1.5. Royalties, excise and taxes ............................................................................................................................ 26 2.1.6. Production capacity ........................................................................................................................................ 26 2.1.7. Supply, market share and competition ....................................................................................................... 27 2.1.8. Logistics and supply chains from well to wheels..................................................................................... 28 2.1.9. Inventory, commercial storage and strategic reserve stockpiles ......................................................... 29 2.1.10. Imbalances between production and consumption and the economics of oil trade ...................... 29 2.1.11. International trade flows of oil and refined products .......................................................................... 30 2.1.12. Physical and financial markets .................................................................................................................. 31 2.1.13. Storage, trading, futures, derivatives and the ‘paper oil’ market ...................................................... 32 2.1.14. The size of the paper markets in oil ......................................................................................................... 33 2.1.15. Demand, prices and price formation ........................................................................................................ 34 2.1.16. Competing fuels ............................................................................................................................................. 34 2.1.17. Energy technologies..................................................................................................................................... 35

2.2. The market, the economy and international institutions ................................................. 35 2.2.1. Geographic distribution and the replacement of oil reserves ............................................................... 35 2.2.2. Market structure: the major players in the physical oil market .......................................................... 36 2.2.3. How the role of swing producer has evolved over time ........................................................................ 40 2.2.4. OPEC concentration and capacity to influence the market .................................................................. 43 2.2.5. OPEC quotas and oil production ................................................................................................................. 45 2.2.6. The management of spare capacity ............................................................................................................. 46 2.2.7. Economics, the value chain, costs and other considerations................................................................. 48 2.2.8. Both supply and demand are inelastic in the short run.......................................................................... 49 2.2.9. Demand may be somewhat more elastic in the short run than has been estimated ....................... 50

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2.2.10. Supply may becoming more price-elastic due to shale oil ................................................................... 50 2.2.11. Supply-demand fundamentals and the volatile dynamics of oil price-formation .......................... 51 2.2.12. Oil market experience of how dynamic economic forces can play out ............................................. 53 2.2.13. The United States light tight oil revolution .......................................................................................... 55 2.2.14. Shale oil and marginal supply is still a significant uncertainty ......................................................... 58 2.2.15. International institutions ............................................................................................................................ 59

Chapter 3. The History and Development of the Global Oil Market 61

3.1. A brief historical outline of the oil market since World War 2 ...................................... 61 3.1.1. How has oil’s role changed over time? ....................................................................................................... 62

3.2. Change and continuity.............................................................................................................. 64 3.2.1. Phase 1: Stability and growth—the early years of OPEC ..................................................................... 64 3.2.2. Phase 2: Conflict and ‘stagflation’—the IEP Treaty and the formation of the IEA ....................... 64 3.2.3. Phase 3: Stability and growth in the ‘New World Order’ ..................................................................... 65 3.2.4. Phase 4: ‘Return of history,’ Chinese super-growth, financial crisis and stalled growth .............. 65

3.3. What can we learn from the 1970s? ...................................................................................... 66 3.3.1. Strategic responses of OECD countries to the supply shocks of the 1970s ...................................... 67 3.3.2. Policy and market responses to the demand surge of the 2000s ......................................................... 69 3.3.3. Lessons of the 1970s for OECD countries ................................................................................................ 71 3.3.4. Lessons of the 1970s for OPEC countries ................................................................................................. 72

3.4. Oil security ................................................................................................................................. 73 3.4.1. Oil supply disruptions both recent and historical ................................................................................... 73 3.4.2. Market responses to supply shocks including speculative demand shocks ....................................... 75 3.4.3. The role of market prices and price volatility .......................................................................................... 75 3.4.4. The IEA system of oil supply security and Australia’s experience ..................................................... 76 3.4.5. The role of spare capacity .............................................................................................................................. 77 3.4.6. The objective of IEA collective action contrasts with OPEC’s publicly-stated objective ............. 78 3.4.7. Stockdraw and the IEA emergency reserves system .............................................................................. 78 3.4.8. The role of the IEA in view of the development of the market ........................................................... 79 3.4.9. Changes and developments in the oil market ........................................................................................... 79 3.4.10. Valuing oil security ....................................................................................................................................... 82 3.4.11. Estimating the probabilities, magnitudes and durations of future disruptions ............................. 83

3.5. Analysis of differences and similarities in the oil market from 1975 to 2015 .............. 86 3.5.1. Market information and data transparency .............................................................................................. 86 3.5.2. Comparing the oil market in 2015 with 1975 to identify similarities and differences ................... 87 3.5.3. What did we ‘know’ for certain that has turned out not to be the case? ........................................... 92 3.5.4. The paradox of spare oil production capacity ........................................................................................... 93 3.5.5. Dilemmas faced by the swing producer ..................................................................................................... 94 3.5.6. The shale revolution is changing the responsiveness of oil supply to changes in price ................ 95 3.5.7. The ability of the market mechanism to manage supply risks proactively ....................................... 95 3.5.8. How shale oil interacts with spare capacity and other means of balancing the market ................. 96 3.5.9. Oil and the macro-economy: the causes and consequences of oil price shocks ................................ 99

3.6. Oil market influences and ‘surprises’................................................................................... 100 3.6.1. Geology and geography ............................................................................................................................... 100 3.6.2. Technology ..................................................................................................................................................... 100 3.6.3. Probabilities and risk .................................................................................................................................... 101 3.6.4. Economics ........................................................................................................................................................ 101 3.6.5. Alternative energy sources.......................................................................................................................... 101 3.6.6. Commerce and governance ......................................................................................................................... 102 3.6.7. Banking, finance and the monetary system ............................................................................................. 102 3.6.8. National and international institutions .................................................................................................... 103

3.7. Reconsidering ‘popular wisdoms’ about the oil market .................................................. 103

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3.7.1. Comparing the ‘supply shocks’ of the 1970s and the ‘demand shock’ of the 2000s ...................... 103 3.7.2. The influence of monetary policy—market data on oil, dollars and gold ....................................... 107 3.7.3. A long historical perspective on oil, dollars and gold .......................................................................... 109 3.7.4. Turning points in the price cycle clearly mark the major oil pricing eras in history .................. 110 3.7.5. Risk, return and reserves: a comparison with banking reserves ....................................................... 113

Chapter 4. The Outlook for the Oil Market 115

4.1. Contrasting perspectives ....................................................................................................... 115 4.1.1. The ‘JAM’ thesis: oil is ‘Just Another Market’ ....................................................................................... 115 4.1.2. Antithesis: oil is an exception ..................................................................................................................... 116 4.1.3. Synthesis: oil is indeed special, but market-based approaches work best ........................................ 116

4.2. Frameworks to guide views................................................................................................... 116 4.2.1. Oil prices viewed through the lens of affordability ............................................................................... 117 4.2.2. Policy considerations relevant to oil—depletion, abundance and the environment ..................... 118 4.2.3. The Energy Policy Trilemma: trading off security, affordability and sustainability ................... 119 4.2.4. The key role of expectations ....................................................................................................................... 120 4.2.5. The influence of policy priorities on the outlook for oil ...................................................................... 121 4.2.6. The role of geopolitics .................................................................................................................................. 122

4.3. Trends and possibilities in the next oil pricing era ......................................................... 122 4.3.1. Clear trends in train with strong momentum ........................................................................................ 123 4.3.2. Significant uncertainties and implications .............................................................................................. 125

4.4. Implications for major stakeholder groups of the evolution of the oil market.......... 126 4.4.1. Implications for oil importers including key countries in Asia .......................................................... 126 4.4.2. Implications for oil exporters and their NOCs ...................................................................................... 126 4.4.3. Implications for IOCs ................................................................................................................................... 127 4.4.4. Implications for international institutions .............................................................................................. 127

Chapter 5. Summary and conclusions 128

5.1. Summary ................................................................................................................................... 128

5.2. Concluding observations ....................................................................................................... 130

5.3. Avenues for policy development and modernisation ....................................................... 132

Chapter 6. Appendices 133

6.1. Major historical oil supply disruptions and recent international trade flows ............ 133 6.1.1. Oil supply disruptions since 1950 ............................................................................................................. 133 6.1.2. The 1973 oil crisis: a chronology of selected events ............................................................................. 134 6.1.3. Crude oil and refined product trade flows ............................................................................................... 136

6.2. International organisations ................................................................................................... 136

References and further reading 139

Endnotes to the text 144

Figures

Figure 1 History of oil consumption, production, exports and prices, 1965-2015 ...................................................................... 3

Figure 2 The energy evolution cycle ....................................................................................................................................................... 4

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Figure 3 The prices of oil relative to gold throughout the eras of the oil industry .................................................................... 7

Figure 4 Global oil production-consumption and import-export balance, 2015 ......................................................................... 8

Figure 5 Shares of global crude oil imports by destination, 1965-2015 ......................................................................................... 9

Figure 6 Shares of global crude oil exports by origin, 1965-2015................................................................................................ 10

Figure 7 Australia’s oil production, consumption and net imports, 1965-2015 ........................................................................ 13

Figure 10 Australia’s crude oil expenditure as share of GDP and Australian recessions ...................................................... 13

Figure 8 United Kingdom’s oil production, consumption, net imports and exports, 1965-2015 ......................................... 14

Figure 9 United States’ oil production, consumption and net imports, 1965-2015 ................................................................. 15

Figure 11 Oil export revenue dependence of selected key countries, 2014 ................................................................................ 16

Figure 12 History of crude oil production, imports and exports in the United States, 1900-2015 ..................................... 18

Figure 13 The geographic distribution of oil reserves .................................................................................................................... 20

Figure 14 Reserves-to-production ratios by region and for the world ....................................................................................... 21

Figure 15 Project status categories and commercial risk ............................................................................................................... 22

Figure 16 Indices for the capital costs of upstream oil production and oil prices .................................................................... 24

Figure 17 Example of typical capital cost, operating cost and production profile for conventional oil ............................. 25

Figure 18 Example of the cross-commodity relationship between oil and steel prices .......................................................... 26

Figure 19 Market shares of global oil production, 1965-2015 ...................................................................................................... 28

Figure 20 High-level overview of the oil value chain ...................................................................................................................... 28

Figure 21 Visualisation of global oil production, trade and consumption, 2014 ...................................................................... 29

Figure 22 The interconnections between physical and financial markets for oil ..................................................................... 32

Figure 23 A snapshot of the Brent Crude Oil futures market........................................................................................................ 33

Figure 24 Global shares of oil and other fuels, 2015 ........................................................................................................................ 34

Figure 25 Sovereign control of oil reserves ........................................................................................................................................ 37

Figure 26 Reserve production ratios .................................................................................................................................................... 37

Figure 27 Oil production by Saudi Arabia and the United States, 1965-2015 .......................................................................... 40

Figure 28 Oil exports by Saudi Arabia and oil imports by the United States, 1965-2015 ..................................................... 41

Figure 29 Oil exports by Saudi Arabia and the CIS and oil imports by the United States, 1965-2015 ............................. 42

Figure 30 Oil exports by Saudi Arabia and imports to the United States, China and India, 1965-2015 ........................... 42

Figure 31 Changes in concentration and OPEC’s degree of influence, 1965-2015 .................................................................. 43

Figure 32 OPEC and Saudi Arabia announced production quotas, 1982-2015 ........................................................................ 45

Figure 33 OPEC and non-OPEC supply disruptions....................................................................................................................... 46

Figure 34 Changes in Saudi Arabia crude oil production and WTI crude oil prices ............................................................... 47

Figure 35 OPEC spare production capacity and WTI crude oil prices....................................................................................... 47

Figure 36 Long-term oil-supply cost curve ........................................................................................................................................ 48

Figure 37 Porter’s Five Forces super-imposed on a Marshallian cross ...................................................................................... 51

Figure 38 Percent change in the real price of oil, Feb 1948 – Dec 1973 and Feb 1974 – May 2013 .................................. 52

Figure 39 The dynamics of price formation within volatile commodity markets .................................................................... 53

Figure 40 Evolution of world crude oil consumption and international prices, 1965-2015 .................................................. 54

Figure 41 Indices for the capital costs of upstream oil production and oil prices .................................................................... 55

Figure 42 Supply costs of liquid fuels ................................................................................................................................................... 56

Figure 43 World supply cost curves for 2013 and 2035 in the IEA New Policies Scenario ................................................. 56

Figure 44 Non-OPEC supply cost curves for 2015 and 2040 in the IEA New Policies Scenario ........................................ 57

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Figure 45 North America oil and gas rotary rig count by target, 1987-2016 ........................................................................... 58

Figure 46 North America oil and gas rotary rig count by drilling trajectory, 1991-2016 .................................................... 59

Figure 47 Oil, gas, coal and non-fossil fuel as a share of world primary energy supply, 1965-2015 .................................. 63

Figure 48 Oil share of primary energy in the world, and selected major economies, 1965-2015 ........................................ 63

Figure 49 Year-on-year changes in the nominal price of crude oil .............................................................................................. 67

Figure 50 Timeline of oil supply disruptions and IEA collective actions ................................................................................... 74

Figure 51 The IEA Emergency Response System ............................................................................................................................ 77

Figure 52 The price of crude oil in the regulated and market eras before and after 1974 ..................................................... 80

Figure 53 Global real activity and the real price of oil, 1973-2008 .............................................................................................. 82

Figure 54 Benefits of Emergency Oil Stocks: Simulation Framework ........................................................................................ 83

Figure 55 World Oil Disruption Influence Diagram ....................................................................................................................... 84

Figure 56 An estimate of the probability distribution for disruption of global oil supply ..................................................... 86

Figure 57 History of oil prices and selected forward curves, 1990-2016 .................................................................................... 96

Figure 58 Comparison of supply side contributors to oil market balancing .............................................................................. 97

Figure 59 Correlations between US active horizontal drilling rig count and lagged WTI crude oil price ...................... 98

Figure 60 Brent crude oil daily nominal prices relative to January 2000 in US dollars ....................................................... 108

Figure 61 Brent crude oil daily nominal prices relative to January 2000 in the major currencies .................................... 108

Figure 62 Brent crude oil daily prices relative to January 2000 in the major currencies and gold ................................... 109

Figure 63 Long history of annual average crude oil prices in nominal and real US dollar terms ..................................... 110

Figure 64 A long history of annual average crude oil prices relative to gold ......................................................................... 111

Figure 65 Long history of United States interest rates ................................................................................................................. 113

Figure 66 Change in United States and UK bank equity, 1880-2005 ........................................................................................ 114

Figure 67 World crude oil expenditure and implied cost of production as share of GWP .................................................. 118

Figure 68 The Energy Policy Trilemma ........................................................................................................................................... 120

Figure 69 The IEA share of world oil imports is falling rapidly ................................................................................................ 123

Tables

Table 1 A timeline of eras in the history of the oil industry since 1859......................................................................................... 5

Table 2 Summary of crude oil and refined product trade flows, share of total, 2015 .............................................................. 30

Table 3 The world’s largest oil and gas producing companies ...................................................................................................... 38

Table 4 Evolution of the oil demand, supply, exports, imports and pricing since World War II ....................................... 62

Table 5 Policy options and strategies available to importers in response to oil security challenges .................................. 68

Table 6 Assessment variables in the order they were assessed by a United States expert panel ......................................... 85

Table 7 Similarities and differences relevant to oil between 1975 and 2015 ............................................................................. 89

Table 8 Phases in the United States light tight oil industry (horizontal drilling and shale oil fracking) .......................... 99

Table 8 Overview of the timing of the energy evolution cycle, 1970s and 2000s .................................................................. 104

Table 9 Analysis comparing the forces at the break point and in rebalancing, 1970s and 2000s ...................................... 106

Table 10 Shifts in the priority of policy concerns since World War 2 ...................................................................................... 121

Table 11 Change in composition of the IMF Special Drawing Rights currency basket ...................................................... 124

Table 12 List of oil supply disruptions and instances of IEA Collective Action, 1950-2015 .............................................. 133

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Table 13 Summary of crude oil and refined product trade flows, million tonnes, 2015 ....................................................... 136

Boxes

Box 1 The first oil shock and policy lessons ....................................................................................................................................... 70

Box 2 The second oil shock and policy lessons .................................................................................................................................. 71

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Abbreviations used in this paper

bbl Barrel: derived from ‘blue barrel’ for standard 42 US gallon barrels

boe Barrel of oil equivalent: used to enable natural gas and oil production to be added together

CapEx Capital Expenditure: up-front investment

CERM The Collective Emergency Response Mechanism of the IEA for release of emergency reserves

CIS Commonwealth of Independent States

ENI Italian oil company, originally: "Ente Nazionale Idrocarburi" (national hydrocarbons authority)

EPAA The Emergency Petroleum Allocation Act, signed by President Nixon in 1973

EPCA Energy Policy and Conservation Act, signed by President Ford in 1975

GDP Gross Domestic Product

GWP Gross World Product

HHI Hirschmann-Herfindahl Index of market concentration

IEA The International Energy Agency, part of the OECD, based in Paris

IEF International Energy Forum

IMF International Monetary Fund

ICE The Intercontinental Exchange, formerly the IPE, a commodities futures exchange in London

IEA International Energy Agency

IEP Agreement on an International Energy Program: the treaty establishing the IEA

IOC International Oil Company

IPA International Petroleum Agreement (IPA) between the host country government and the IOC

IPE International Petroleum Exchange, an oil futures exchange in London, since renamed the ICE

LNG Liquefied Natural Gas: methane (CH4) at –161ºC

LTO Light tight oil: oil from shale beds, produced by horizontal drilling and hydro-fracking

Mboepd Millions of barrels of oil-equivalent per day (allows gas and oil to be added together)

Mbpd Millions of barrels per day (a volumetric measure of oil)

MENA The Middle East and North Africa

NGLs Natural Gas Liquids: mainly ethane (C2H6), propane (C3H8), and butane (C4H10)

NOC National Oil Company

OAPEC Organisation of Arab Petroleum Exporting Countries, based in Kuwait

OECD Organisation for Economic Cooperation and Development, based in Paris

OPEC Organization of the Petroleum Exporting Countries, based in Vienna

OpEx Operating Expenditures: the ongoing costs of operating and maintaining an asset

ORF Other refinery feedstocks

SDR Special Drawing Rights: the supplementary foreign exchange reserve assets of the IMF

SPR Strategic Petroleum Reserve: an emergency oil and petroleum stockpile

SOCAL Standard Oil of California (SOCAL), now Chevron

toe Tonne of oil-equivalent

WEC World Energy Council

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Glossary of terms used in this paper

Term Explanation

Adverse supply shock

‘An unexpected shift of the supply curve to the left, i.e. a reduction in the quantity supplied for any given price. This could result from natural disasters such as floods or earthquakes; from human, animal or plant diseases; or from major political upheavals such as war or revolution. To oil importers, the sudden price increases imposed by the Organization of Petroleum Exporting Countries in the 1970s appeared as adverse supply shocks. Such a shock reduces the real income an economy can produce even at full employment of its available resources. Supply shocks are used as a modelling device in macroeconomics to represent aggregate economic risk.’ —The Oxford Dictionary of Economics

Arbitrage Arbitrage is the opportunity to obtain a riskless profit from buying a good or asset in one market where the price is low, and simultaneously selling in another market where the price is higher. Arbitrage tends to prevent the price of the same good or asset in different markets from moving further apart than a margin equal to transaction costs. Interest arbitrage is borrowing in a market with lower interest rates and simultaneously lending in a market with higher ones. —The Oxford Dictionary of Economics Inter-temporal arbitrage opportunities get traded away, and as a result the forward curve is smooth at the end of a trading session.

Backwardation A situation in which the futures price (or forward price) of a commodity is lower than the spot price.

Barrel, bbl A ‘blue barrel’, a unit of volume, equal to 42 US gallons or about 158 litres.

barrels of oil equivalent, boe

A unit for measuring the total oil, other liquids and gas production, typically used for consolidated reporting of all upstream hydrocarbon production, as the three products are often produced from common wells.

Break point The term ‘break point’ (attributed to the Canadian energy economist Peter Tertzakian) is not (or not yet) a standard term in the economic literature. However, it describes succinctly the moment that a trend ‘breaks’ or fails to continue. It is an apt description of what happened with oil in 1973-74 and again in 1979-80. In this paper, the term ‘break point’ is distinguished from the conventional term ‘shock’ or ‘adverse supply shock.’ The two ideas are related but not interchangeable.

The Commonwealth of Independent States

The CIS was formed when the former Soviet Union dissolved in 1991. At its conception the CIS consisted of ten former Soviet Republics: Armenia, Belarus, Kazakhstan, Kyrgyzstan, Moldova, Russia, Tajikistan, Turkmenistan, Ukraine, and Uzbekistan. Azerbaijan and Georgia later joined the association in 1993. In 2005, Turkmenistan withdrew from the CIS, and is now classified as an associate member.

Contango A situation in which the futures price (or forward price) of a commodity is higher than the spot price.

Discount rate The interest rate at which future receipts or payments are discounted to find their present value. If the discount rate is 100r per cent per annum, the present discounted value of a payment of A due in T years’ time is V = A/(1+r)T. —The Oxford Dictionary of Economics

Derivative contract

A derivative contract, or ‘derivative’ for short, is a financial security that is dependent upon or derived from one or more underlying assets. Derivative contract is a general term that includes contracts for future delivery ‘futures’ as well as option contracts.

Economic rent ‘A payment for the services of an economic resource above what is necessary for it to remain in its current use.’ —The Oxford Dictionary of Economics See also natural resource rent.

External break-even oil price

The oil price at which the current account balance is zero, for any particular country. Estimates are calculated and published by the IMF.

Fiscal break-even oil price

The oil price at which the fiscal balance is zero, for any particular country. Estimates are calculated and published by the IMF

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Term Explanation

Futures contract A futures contract is a legal agreement, generally made on the trading floor of a futures exchange, to buy or sell a particular commodity or financial instrument at a predetermined price at a specified time in the future. A futures contract ‘locks in’ a price and a quantity for both the buyer and seller. Futures transactions are also known as forward sales or forward purchases. They oblige the seller to deliver and the buyer to pay, in contrast with option contracts, which impose no obligation on the holder (purchaser) of the option, and a conditional obligation on the seller of the option.

Gigajoule, GJ A metric unit of energy, approximately equal to 1 million British thermal units (1.055 MMBtu)

Gross Domestic Product

A standard measure of national economic output, net of international remittances

Gross World Product

The sum of gross domestic product for all countries in the world.

Hirschmann-Herfindahl Index

An index of market concentration calculated as the sum of the squares of market share. A market with one supplier (monopoly) will have an HHI of one. A market with two suppliers with equal market shares will have an HHI of 0.5, and so on. A market with an HHI of 0.25 is considered an oligopoly. A market with an HHI of 0.15 or below is considered to be unconcentrated or ‘competitive.’

Monte Carlo method

‘A method of investigating the behaviour of economic models [that] are too complicated for analytical solutions to be possible. A system is started off at a large number of initial positions chosen at random, and followed through a numerical simulation to see how it evolves. Monte Carlo methods can be used to check whether a system has an equilibrium, and whether this is stable for any starting point, or for some limited region of starting points.’ —The Oxford Dictionary of Economics

Natural resource rent

Natural resource rent arises from the differential between the resources with the lowest cost of development and production, and the marginal resources with the highest costs. The differential tends to be wide in natural resources (in contrast with manufacturing, for example), and oil is not an exception. Oil may, for periods in the price cycle when the market is tight, attract scarcity rents, and monopoly rents, which are other forms of economic rent.

Oil-long and oil-short countries

Oil-long countries are those who produce more oil than they consume and oil-short countries are those who consume more oil than they produce. Exports and imports are on a spectrum. At the end of the spectrum with 100 per cent imports are countries such as Japan and Korea with no known oil reserves, which have no choice but to import oil. At the other end of the spectrum are countries with very low domestic consumption but large, commercially attractive oil reserves, which export most of their production. In between are found ‘oil short’ countries such as the United States and China that produce large quantities of oil but are also net importers and ‘oil long’ countries the consume significant quantities of oil, but which are also net exporters such as Canada, for example.

Open interest Also known as open contracts or open commitments, refers to the total number outstanding of derivative contracts that have not been settled (offset by delivery). For each buyer of a futures contract there must be a seller. The majority of futures contracts are closed out financially (settled by an equal and opposite transaction) prior to physical delivery.

Option contracts An options contract is a financial instrument in the form of an agreement between a buyer and seller that gives the purchaser of the option the right to buy or sell a particular asset at a later date at an agreed upon price. Options contracts are often used in securities, commodities, and real estate transactions. A ‘put option’ gives the holder, who has purchased the contract from the seller of the option for a price known as the premium, the option (but not the obligation) to sell the underlying asset at a particular price on a particular date. A ‘call option’ gives the holder, who has purchased the contract from the seller of the option for a price known as the premium, the option (but not the obligation) to buy the underlying asset at a particular price on a particular date. A standard contract for physical oil of a specified grade delivered at a specified location is an example of an underlying asset. The premium represents the value of the option at any point in time, and is a function of the volatility of the underlying asset, the difference between the current price and the agreed price or ‘strike price’ and the time to maturity. As those variables change over time, the value of options changes continuously, and there is a market for trading options.

Rent See natural resource rent

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Term Explanation

‘Seven Sisters’ A term first coined in the 1950s by Enrico Mattei, then head of the Italian state-owned oil company ENI to refer to the ‘Consortium for Iran’ formed following the suggestion of the United States State Department following Iran’s nationalisation of its oil industry in 1951. The ‘seven sisters’ group comprised Anglo-Persian Oil Company (now BP); Gulf Oil, Standard Oil of California (now Chevron), Texaco (later merged with Chevron); Royal Dutch Shell; Standard Oil of New Jersey (Esso/Exxon) and Standard Oil Company of New York (Socony) (trading as Mobil now part of ExxonMobil).

Shock ‘In economics, an unexpected and unpredictable event that has a positive or a negative effect on the economy. A shock is said to be permanent if it has a long-run effect, for example, economic effects of major geographical discoveries or major technical developments; otherwise it is said to be transitory: for example, monetary or fiscal policy changes may have no long-run effect on real income.’ —The Oxford Dictionary of Economics

Tonne of oil-equivalent, toe

A unit of energy (not mass) equal to 10 Gcal and approximately but not exactly equal to one physical tonne of oil

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The paper is structured as follows:

Chapter 1 provides an overview and introduction, including key questions prompted by the profound generational changes underway in oil markets and key themes in the evolution and development of the oil market. A framework to make sense of the historical data and to guide the outlook is provided along with alternative perspectives, long-term data, patterns and historical parallels, including a timeline of eras in the history of the oil industry since 1859. The geographic balance of supply and demand is presented, as well as changes in the geographic shares of oil imports, changes in the geographic shares of oil exports, oil import dependence and independence and oil export revenues and mutual inter-dependence between exporters and importers.

Chapter 2 on the current state of the oil market describes the key characteristics of the market today. It then provides an overview of the key institutions that relate to the oil market. Then, responding to the IEA’s recent observation that ‘[o]il markets have changed enormously since the first oil shock of 1973-74,’ it analyses the differences and similarities in the market in the 40 years from 1975 to 2015. Finally, the section concludes with a review of the relative influences on the market and how they interact, historical ‘surprises’ and what we can learn from them.

Chapter 3 provides background context on the history and development of the global oil market. It begins with a brief summary of the history of the oil market since World War II, including a summary of oil supply disruptions, and how the role of oil has changed over the decades. Continuity and change through four major phases of the market are then reviewed. Lessons from the 1970s are inferred from the strategy and policy choices of companies and governments in OPEC, OECD and other countries, and the behaviour of producers and consumers as expressed in the market. Some popular wisdoms are then analysed, including a side-by-side comparison of the ‘supply’ shocks of the 1970s and the ‘demand’ shock of the 2000s. The section concludes with a brief review of the situation of Australia and selected other countries, showing that each country is unique, although there are parallels between the circumstances of oil importing countries.

Chapter 4 on the outlook for the oil market, sets out the ‘JAM’ thesis that oil is ‘just another market’, contrasts this with the antithesis that oil is special and cannot be treated just like other commodities, and then resolves these polarised perspectives via synthesis. The outlook for the oil market is explored through a review of market trends and current institutional arrangements, viewed through the prism of the Energy Policy Trilemma, and government policy-makers’ priorities in making difficult trade-offs between the competing objectives of oil and energy supply security, affordability and environmental sustainability. Finally, the implications of the differences and similarities between the current oil market and that of the mid-1970s are drawn out, comparing different perspectives. The outlook for OPEC, which recently turned 55 and the IEA, which recently turned 40, are discussed.

Chapter 5 presents the paper’s summary and conclusions. A clear lesson from history is that disruptions to oil supply tend to occur when there is pressure build up in the energy evolution cycle. A key role for international institutions is to act as a pressure relief valve to avoid severe adverse consequences. However, if imbalances are not sustainable, then a break point is inevitable, rebalancing is required and cannot be prevented. Markets are rarely perfectly balanced, but are usually tight and getting tighter before they loosen dramatically, or loose and getting looser before they tighten dramatically. Markets are always rebalancing. Price signals play a key role in the process. The challenge for international institutions is to relieve dangerous pressure buildup without delaying the necessary rebalancing, which would only lead to greater pressure build-up and a more severe break point.

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Chapter 1. Overview and introduction

More than 150 years since the industry began producing ‘rock oil’ in Pennsylvania before the American Civil War, crude oil still occupies the prime position in the world’s energy supply. Although consumers today pay a lot more for a unit of energy in the form of oil than for most forms of energy,16 its ease of storage and transport continue to make it a commercially attractive fuel.

At a global level, the oil supply and demand are very finely balanced. Large price swings—both upwards and downwards—are needed to correct relatively small imbalances between production and consumption. The oil market is the world’s largest balancing market, both in terms of the proportion of the physical market balanced by exports and imports, and in terms of the financial value of the commodity traded. In the 1970s, the Organisation of Petroleum Exporting Countries (OPEC) accounted for almost all exports in the international market. Today, the huge balancing market made up of international oil exports and imports represents about half of all oil production and consumption, and OPEC accounts for a little over half of that traded market.

Under normal market conditions, Saudi Arabia plays a key role in balancing the market. Saudi Arabia has by far the lowest oil production costs of any country in the world, and so is able to capture significant economic rents from the balancing service it provides to the market. There is no separate market or payment mechanism for the provision of oil market balancing services. To capture these rents, Saudi Arabia requires co-operation with fellow member countries in OPEC to ensure it is not giving up market share.

While OPEC does not have a particularly strong market position relative to total world oil production, it retains a very dominant position relative to oil exports. Despite the export market for oil not being as highly concentrated as it was prior to 1980, competition for oil imports is growing as oil demand growth shifts relentlessly eastwards as Asian economies develop. This demand trend is combined with the reality that most countries in Asia and the region as a whole are oil-short: their oil demand exceeds their domestic oil supply, and the gap is widening.

The IEA has noted that ‘[o]il markets have changed enormously since the first oil shock of 1973-74.’ A few of the significant changes include, the oil market emerging as one of the largest and most efficient markets in the world, oil has become increasingly affordable, and the market and economies have become more resilience to supply disruptions. Over this period, there has also been increasing evidence leading to the recognition that demand, (not supply) largely accounts for price shocks.

This paper addresses the question: How have the oil market and institutions evolved since the 1970s and what new challenges will they face in the coming decades? The paper takes a ‘generational’ perspective: looking back over the 70 years since World War 2 and looking forward over the 35 years to 2050. Major trends of global significance tend to evolve over such timeframes and should provide the basis for assessment of oil market changes and their associated institutions.

1.1. Key questions prompted by the profound generational changes in oil markets

This paper addresses the following key questions:

Markets: Production and consumption, costs, royalties and taxes: how are prices formed?

Institutions: What role do institutions play with respect to the market for oil?

Change: In what ways was the oil market of 2015 different from the oil market of 1975?

Continuity: In what ways was the oil market of 2015 similar to the oil market of 1975?

Influences: What are the key factors at work and to what extent do they affect the oil market?

Surprises: What did we ‘know’ for certain that has turned out not to be the case?

Priorities: How do government policies balance price, security and environmental concerns?

Outlook: What do the answers to these questions tell us about the future? 16 The exceptions are electricity, and LNG in Asia. But electricity is an energy carrier, not a primary source, and Asian LNG prices

reflect the high costs of storing natural gas and transporting it over long distances.

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1.2. Key themes

Markets are not static, but are constantly evolving, with ongoing reciprocal influence between them and their supporting international institutions. As markets evolve, questions arise as to the most appropriate way to adapt in recognition not only of the current market realities but also of likely future developments. The inclusion of the Chinese currency, the RMB in the Special Drawing Rights (SDR) basket of the International Monetary Fund (IMF) is an example of an international institution adapting to economic and market changes.

In the energy sector, the IEA has begun the process of considering the types of reforms needed in response to changes in the energy sector and energy markets, including the oil market. The first of the three pillars set out for IEA reform includes enhanced engagement with major emerging economies. That pillar reflects the remarkable shift of energy demand, including oil demand, from west to east since the beginning of the present century.

This paper explores the ‘JAM’ thesis that oil is ‘just another market.’ It then contrasts the antithesis that oil is in some way special or an exception to other commodity markets or markets in general. Then a synthesis is drawn out that oil is indeed special, but experience from the 1970s to the present suggests that market-based approaches work best at ensuring affordable, accessible and secure supply of oil in particular and of energy in general.

1.2.1. The evolution and development of the oil market

Prices and quantities are a natural place to begin to assess the evolution of the oil market. Figure 1 shows the history of oil consumption by production source (domestic, imports from non-OPEC exporters and imports from OPEC exporters), as well as the history of annual average benchmark prices, adjusted for inflation. The figure shows clearly the two ‘oil shocks’ of the 1970s, and the more recent price peaks. Similar price patterns occurred in other commodity markets at the same time.

Low cost oil is a key contributor to economic growth, which in turn encourages oil dependency. High cost oil tends to dampen growth and may trigger economic recessions. A sustained and growing imbalance between supply and demand leads to pressure build-up. In the short-run, supply and demand are balanced by storage, and by flexible ‘spare capacity.’ In the long-run, supply and demand are balanced by investment, retirement and substitution.

The build-up of fundamental demand pressure on supply can be seen very easily in Figure 1. Extrapolating the trend of oil consumption volumes from 1965 to 1973 results in the trend line reaching 100 Mbpd by the early 1980s. After more than three decades of exploration, technology development, and enormous growth in capital investment, by 2016 global production and consumption has not reached 100 Mbpd. The world consumed about 95 Mbpd in 2015. This clearly indicates that the proven reserves, industry capability including technology, human resources and supply chains of the 1970s were simply not up to the task of meeting continuation of the 1960s and 1970s demand growth trend at any oil price. That is very different from saying that the world was about to ‘run out of oil’, a conclusion reached by many in the 1970s, including experts and policy-makers in some countries.

The global oil market is very finely balanced and requires large price swings to rebalance supply and demand. Figure 1 shows the contrast between volumes and prices adjusted for inflation, and highlights that, proportionally, changes in price can be many times larger than changes in quantities.

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Figure 1 History of oil consumption, production, exports and prices, 1965-2015

Sources: Author’s calculations using data from the BP Statistical Review of World Energy, 2016

Figure 1 also shows the composition of supply grouped in three categories: individual countries’ own internal domestic oil production and consumption; total oil export volumes from non-OPEC countries (essentially trade between non-OPEC countries, since OPEC countries do not import oil); and total oil export volumes from OPEC countries (which is all imported by non-OPEC countries). This shows that OPEC enjoyed a near-monopoly on oil exports in the mid-1970s.

It is apparent that OPEC suffered a severe erosion of market share in the early 1980s; at the same time as world oil consumption was falling, non-OPEC exports were increasing, and domestic oil production for domestic consumption was increasing. Prices fell steeply and OPEC experienced an absolute reduction in export quantities, leading to extremely severe reductions in oil export revenues in real terms.

1.2.2. A framework to make sense of the historical data and to guide the outlook

Along with rapid demand growth, the early 1970s saw policy forces that reflected international tensions and conflicts that emerged in the 1950s and 1960s, combined with social forces characterised by civil unrest within the West, conflicts and wars in the Middle East, as well as the major geopolitical forces of the Cold War era. Environmental forces, epitomised by the Club of Rome publications, were in their infancy and beginning to gain attention. Eventually the buildup of pressure from these forces leads to a break point, leading to a rebalancing. This is the ‘energy evolution cycle,’ as illustrated in Figure 2.

A break point (defined in the glossary on page xvii) should not be conflated with a ‘shock’ as commonly used in the economic literature, nor with an ‘adverse supply shock’ (also defined in the glossary). Rather, a break point is the turning point or an end of a trend. It naturally entails disruption.

Why did the 1965 to 1973 oil market trend lines for price and quantity not simply continue? The answer is: because they could not. The world had been on a path that we can now see was technically, economically, and financially (for producers) unsustainable. Oil production and consumption could not simply keep increasing at very high growth rates while real prices declined. It was physically impossible for the trend to continue. It must be noted that this is somewhat counter to the conventional wisdom that the Arab Oil Embargo ‘caused’ the first oil ‘oil shock.’ The evidence suggests that the embargo was the occasion, but not the cause. The re-alignment of supply and demand, costs and prices, investment and consumer behaviour

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that occurred throughout the 1970s and into the 1980s was chaotic. Sudden changes in nominal price levels generated large macroeconomic ripples around the world.

Figure 2 The energy evolution cycle

Source: Adapted by author from Peter Tertzakian, 2007, A Thousand Barrels a Second: The Coming Oil Break Point and the Challenges Facing an Energy Dependent World, McGraw-Hill, Figure 1.1

However, to reduce the explanation of the oil market in the 1970s to external geopolitical events alone, is to overlook the fact that there was a significant buildup of pressure underway driven by economic fundamentals: that is, an identifiable set of forces other than geopolitical factors. The break point was inevitable, because things could not continue to go on as they had before.

It is notable that the OPEC ‘oil shock’ has become such a touchstone example of an adverse supply shock that it is included in the dictionary definition, (see the glossary). This shows the extent of the impact of the events of the 1970s. Even though there were prior causes with economic explanations leading to the disruption, the disruption is often viewed as if it was an unpredictable event.

1.2.3. Alternative perspectives, long-term data, patterns and historical parallels

Table 1 presents a timeline and brief summary of notable events of interest in the development of the oil industry from 1859 to the present. The timeline is divided into eras, inspired by the work of Luciani (2010), with the author’s own additions, refinements and modifications.

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Table 1 A timeline of eras in the history of the oil industry since 1859

TIMELINE 1859 1882 1911 1933 1970 1983 1987…

Period: 1859-1882 1882-1911 1911-1933 1933-1973 1974-1983 1983-1987 1987-present

Era Innovation and consolidation

Standard Oil Trust [Transition period] ‘Seven Sisters’2 OPEC pricing [Transition period] Global market

Pricing regime Refiners play the key role

Monopoly Oligopoly Posted prices controlled by the companies

Posted prices controlled by the export countries

Netback pricing Reference pricing against benchmark crudes

Notable landmarks

1850s: Discovery, applications stimulate demand, competition between suppliers, then consolidation and control 1857: first oil concession in the United States. ‘Rock oil’ for lamp fuel. Rail rates key. Pipelines displace rail: refineries relocate to ports. 1871: Standard Oil alliance in response to price collapse

1882: Trust structure used for centralised management of companies 1890: Sherman Antitrust Act 1899: Standard Oil Company (New Jersey) created, which becomes the parent company; Standard Oil controlled 90 to 95% of all the oil refined in the United States 1911: Supreme Court divides Standard Oil

1914-18: WW1

Oil price volatility: 1915: $0.64 ($14.93 in 2015$) 1920: $3.07 ($36.30 in 2015$) 1933: $0.67 ($12.25 in 2015$)

1920: Interest rates peak at 5%

1929: Stock market crash; The Great Depression persists to 1939

1931: Bank of England abandons the gold standard

1933: first contract to drill for oil in Saudi Arabia secured by SOCAL

1938: first commercial oil in Saudi Arabia produced by SOCAL 1939-45: WW2 1950s: post-war consumer boom and widespread car ownership 1961: ENI CEO Mattei secures Italy-USSR oil trade agreement 1970: “Seven Sisters” control 85% of world’s petroleum reserves

1971: US President Nixon closes the gold window

1973: Arab Oil Embargo 3 1973: US President Nixon—EPPA 1978: Iranian Revolution 1980: Iran-Iraq war 1980: “Seven Sisters” control less than 25% of reserves 1981: Interest rates peak—10y Treasuries >15% President Reagan decontrols United States oil prices (28 Jan) 1983: OPEC abandons the idea of production cuts to support prices

1983: UK PM Thatcher’s ‘Big bang’ financial deregulation 1983: launch of WTI NYMEX contract (March) ‘paper barrels’ 1984: Shell formalizes 15-day ‘dated Brent’ OTC establishing it as a reference price 1985: Saudi Arabia switches to netback pricing 1986: price collapse, netback pricing abandoned 1987: stockmarket crash, completion of BP privatisation

1988: IPE futures market launched in London 1989: IPE put and call options market launched 1991: Soviet Union dissolved 2008: oil price peak, collapse and rebound 2010-14 2010-15: shale oil revolution, Brent-WTI spread opens 2012: US EIA adopts Brent over WTI for its AEO 4 2014: major price collapse begins 2016: Saudi Arabia fights for oil market share

Key oil supply United States United States United States Saudi Arabia & the Middle East

Saudi Arabia & OPEC

Soviet Union, North Sea

New entrant: US shale oil

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Source: compiled from numerous sources by the author, inspired by Luciani (2010)

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Viewing the oil price in terms of the gold price to remove the monetary policy filter from the data, as shown in Figure 3, provides another perspective that reveals insights.

An observation from Figure 3 is that the beginning and end of each era tends to coincide with the low points in the price of gold relative to the oil price, which seems to be around a ratio of one gram per barrel. Oil in 2015-16 appears to be approaching another such low point. If there is a persistent pattern to the price ratio, then the present era, which began in 1987, may be coming to an end. The previous change of era occurred in 1973. The eras have been defined with reference to the prevailing pricing regime, which changes from one era to the next.5

Figure 3 The prices of oil relative to gold throughout the eras of the oil industry

Sources: Author’s calculations using price data from the United States EIA and currency data from www.fxtop.com

As noted above, a casual observation of the pattern in the data suggests that the present oil-pricing era may be coming to an end: market pressures building in the current down cycle may bring about changes in the pricing regime of the oil industry. This is not to suggest that the reference pricing system per se will necessarily break down and be replaced by another pricing regime. While the transition from the “Seven Sisters” era to the OPEC era did bring about a change to posted prices, the control of those posted prices changed. The underlying approach to oil pricing did not change until Saudi Arabia’s brief and unsuccessful experiment with netback pricing in the 1980s, later replaced by the current reference pricing regime. Nevertheless, it is apparent that the more recent shale oil revolution in the United States has had a material impact on the oil market, and the full ramifications of it are yet to work their way through the system.

There are some parallels between Saudi Arabia’s current battle for market share, and the situation in the 1980s. Luciani (2015) notes that,

OPEC started enforcing quotas to defend the high level of prices at the same time as non-OPEC production was rapidly increasing. By 1985, the production of Saudi Arabia, which had exceeded 11 million barrels per day in 1981, was down to less than 4 million barrels per day. At that point the kingdom abandoned the posted price system, causing a sharp downward correction in prices. After a short episode based on netback pricing, the reference pricing regime was inaugurated, which is in force to this day.

In recent years, the surge in United States shale oil production has been indirectly displacing Saudi oil. This effect was masked from 2011 to 2014 by continual supply outages in various countries and strong

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demand growth. The change in production from Saudi Arabia during the recent decline in prices is considerably smaller, both in absolute and relative terms, than in the 1980s.

1.2.4. The geographic balance of supply and demand

The concentration in the Middle East of high quality, low cost oil reserves with flexible production characteristics contrasts markedly with the geographic distribution of demand for oil products. In the latter half of the twentieth century, demand was focused in the North Atlantic, led by the United States and Western Europe. Japan was the next largest centre of demand. In the twenty-first century, demand is shifting eastwards, and is becoming focused in Asia-Pacific, led by economic growth in China, India and emerging Asia.

Figure 4 presents the balance of oil trade based on the extent to which each country is long or short on oil production relative to consumption. The six largest net exporters of oil in 2015 are identified, as well as the six largest net importers. The figure captures the balance of global production, consumption, net exports and net imports for the five major regions of the world. North America is accounted for by the United States and Canada. Mexico is grouped with Central and South America as Latin America. In 2015, about half of the net exports from Latin America were from Mexico.

Figure 4 Global oil production-consumption and import-export balance, 2015

Sources: Author’s calculations using data from the BP Statistical Review of World Energy, 2016 Note: For net exporters, domestic consumption is shown, accounting for the balance of their production. For net importers, domestic production is shown, accounting for the balance of their consumption. Hence the total length of the bar for net exporters represents their total production and the total length of the bar for net importers represents their total consumption.

Figure 4 illustrates that on a regional basis, Asia is very short on oil relative to its demand. Europe is short on oil, but not to the same extent as Asia. The United States is moderately short on oil (but much less so than before the revolution in light tight (shale) oil production) and the Middle East, Africa and Russia are long on oil. These regional imbalances between production and consumption are the underlying fundamental driver of international oil trade flows, and at the centre of concerns among oil importing countries about security of supply.

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1.2.5. Changes in the geographic shares of oil imports

Figure 5 shows the share of global crude oil imports by major importing country or region from 1965 to 2015. The lower column chart, which reconstructs Figure 1,shows the import market as a proportion of total oil consumption, the difference being the sum of domestically produced and consumed oil globally.

Figure 5 Shares of global crude oil imports by destination, 1965-2015

Sources: Author’s calculations using data from the BP Statistical Review of World Energy, 2016

Oil demand following World War II was concentrated in Europe and North America, while Japan was for many years the largest market in Asia. Those northern hemisphere markets are now mature, with flat or moderately declining oil demand. Global demand is now shifting eastwards, driven by the economic rise of Asia generally, and particularly China, as well as the emergence of India. As a result of the geographic imbalance between oil production and consumption, the international traded market represents about 40 per cent of global supply and demand. The Middle East is the major exporting region, and the main importing region is shifting rapidly from the North Atlantic to East Asia.

As Figure 5 shows, in the late 1960s and early 1970s, Europe accounted for half of global oil imports, followed by the United States and Japan. Together these top three oil importers accounted for more than 80 per cent of imports. The import shares of Europe, the United States and Japan have all declined to less

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than half of the global market. For the time being, Europe remains the largest oil import market. China overtook Japan in 2009 to become the third-largest market, and then in 2014 overtook the United States to become the second-largest oil import market. China imports more oil than any other single country, and on current trends will overtake Europe as the largest oil import market around 2020, probably slightly earlier. In addition, if current trends continue, India will overtake Japan to be the fourth largest oil import market before 2020.

These deep shifts in the geographic balance of oil imports have profound implications, which are discussed further in 4.3.1.

1.2.6. Changes in the geographic shares of oil exports

Figure 6 shows the global share of net oil exports for the six largest oil exporters in 2015, as well as for OPEC as a whole, for OECD as a whole, and for countries that are neither OPEC nor OECD members. (Russia being the largest oil exporter in the world).

Figure 6 Shares of global crude oil exports by origin, 1965-2015

Sources: Author’s calculations using data from the BP Statistical Review of World Energy, 2016 The shares of oil exports in 2015 were: OPEC 60 per cent, OECD 10 per cent and others 30 per cent. In the early to mid-1970s, the split was close to 85-15 between OPEC and others, with OECD oil exports only about one per cent. Since the early 1980s, OPEC’s share of global oil exports has been between 50 and 70 per cent. OPEC’s share of exports has converged on 60 per cent, which is OPEC’s average share since 1980. The export shares of Russia and Saudi Arabia have converged between 17 and 18 per cent. The next largest exporters are Iraq, the UAE and Nigeria: all OPEC members and each with les than 9 per cent. The largest non-OPEC exporter is Canada, which in 2015 had less than 5 per cent of exports.

Figure 6 shows the 1970s transformation of OPEC’s oil export shares took place in several phases:

Growing dependence on OPEC from the mid-1960s to the early 1970s, which shows as growth in OPEC’s share of oil exports

Reduced dependence on OPEC from 1973 to 1983, in the form of a reduction in OPEC’s share of exports

A rebound in OPEC’s share from the mid-1980s to the early 1990s

A convergence of OPEC’s share to about 60 per cent of exports.

Comparing Saudi Arabia’s export share with OPEC’s export share is very informative:

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While OPEC’s share of oil exports globally declined from its all-time peak of 85 per cent in 1974 to the low point of 52 per cent in 1985, Saudi Arabia’s share of exports largely increased from 23 per cent in 1975 to 34 per cent in 1981

Saudi Arabia’s share then fell to 10 per cent in 1985 as it cut production

From 1985 to 1992, Saudi Arabia’s share of global oil exports once again increased, from 10 to 24 per cent, with that 14 percentage point increase accounting for most of the increase in OPEC’s 15 percentage point increase in the share of exports (from 52 to 67 per cent) over that period.

Comparison of Saudi Arabia’s share of global oil exports with the share of both the then Soviet Union (succeeded by the Russian Federation and the Commonwealth of Independent States (CIS)) and of OECD oil exporters reveals that:

In the early 1980s Saudi Arabia’s share of exports declined as OECD and Soviet production increased to 14 and 24 per cent, respectively, equal to 38 per cent of world exports, by 1985

Saudi Arabia’s share then increased as OECD and Soviet production declined to 12 and 10 per cent, respectively, equal to 22 per cent of world exports, by 1992.

1.2.7. Oil import dependence and independence

Following the events of the 1973-74 oil embargo, concern over oil and energy security was perhaps greatest in the United States, followed by Japan, and western European countries. The policy response of governments led to a very significant shift in the fuel mix, and a strong emphasis on ‘energy independence’, which persists to the present day. The goal of ‘oil independence’ or, more loosely, ‘energy independence’ remains a part of the policy debate in the United States, although it is not universally advocated.6 Japan, which imports 100% of its oil (and of its gas, coal and uranium), shares this perspective.

Due to a lack of domestic resource endowments, Japan has needed to focus on strategies other than independence for energy security. These strategies have included a significant array of measures:

Diversification of the fuel mix

Maintaining substantial spare capacity across energy systems

Diversification of countries of origin within each primary fuel

Equity investment upstream in the sources of supply of oil, coal, and gas

Diversification of supply routes

Diversification of companies supplying energy

Maintaining large emergency oil reserves

Holding substantially larger inventories of nuclear fuel along the supply chain than is typical for other countries

Implementing extensive energy efficiency measures.

Europe is more dependent on energy imports than the United States, but is not fully oil import-dependent like Japan. The energy security strategy of the European Union has tended to reflect that situation. Historically, European oil and gas security strategies have included primary fuel diversification and collaborative commercial investments with suppliers and in infrastructure, along with governments sustaining diplomatic commitment to strong international energy trade relationships. Circumstances vary from country to country throughout Europe, and national policies reflect those individual circumstances, as well as the role of collaboration between the member states of the EU to increase energy security. The priority given to energy security and its emphasis in high level diplomatic efforts increased significantly following the January 2006 and January 2009 disruptions of pipeline natural gas supplies from Russia via Ukraine to the EU. With one or two exceptions, most notably Hungary,7 the EU and its member states chose not to implement the policy of emergency stockholdings in the gas sector. (Cape Otway Associates, 2016). The European Commission considers that ‘The current level of [storage] capacity is considered adequate, even taking account of increasing EU import dependency over time.’ (European Commission, 2016).

China’s situation is comparable to that of Europe in a number of ways. Like Europe, China has domestic oil production. In 2015, China produced 4.3 Mbpd of oil, the fifth largest national production in the world and almost three times the 1.5 Mbpd produced in the EU. China’s oil consumption is already on a comparable scale as EU oil consumption: 12 Mbpd compared with the EU’s 12.7 in 2015. Like Europe, China is also a

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natural importer. China is more comparable to the United States in that it has large coal reserves and production, and is a single state, unlike the EU.

Oil demand growth in Asia has been accommodated to some extent by demand moderation and even slight oil demand reduction in the West and developed economies. Between 2010 and 2015, the largest factor in reducing market pressure from Asian demand growth was the reduction in United States oil imports. The overall trends point to a future in which concerns about oil security of supply throughout Asia generally become comparable to the traditional concerns of the United States, Europe, Japan and the OECD countries, simply because of the expected scale of Asia’s oil imports. This is not to say that there will necessarily be oil security problems, but that the topic will be of increasing concern to governments in Asia, as their imports come to dominate world oil trade.

1.2.8. Australia’s situation has similarities and differences with the world as a whole

Although all oil-importing countries are in one sense ‘in the same boat’ in relying on an international supply chain for an essential commodity, each country’s particular situation is unique. Australia serves as a good example to illustrate this point.

From a global perspective, Australia is a very small oil producer. In 2015, Australia accounted for 0.4 per cent of world crude oil production.8 Australia’s highest share of global crude oil production was 1.1 per cent in 1985 and 2000. Between 1984 and 2003, Australia produced between 0.8 and 1.1 percent of the world’s oil. From 1965 to 2015, Australia has consistently consumed 1 to 1.1 per cent of global oil. During that same period, Australia’s economic output has varied between 1.1 and 2.1 per cent of the global economy, at market exchange rates. For the past decade its share of global economic output has been in the upper half of that range.

Oil production in Bass Strait came online in the 1970s at just the right time to insulate Australia from the impacts of the oil shocks. From production of just 45 thousand barrels per day (kbpd) in 1969, production had ramped up to over 400 kbpd by 1973, and stayed above that level through to 1983, well after the second oil shock. By 1985, Australia’s oil production was more than 600 kbpd, and was sustained between 550 and 650 to 1999, with a brief surge to 800 kbpd in 2000, followed by steady decline since. Production fell below 600 kbpd in 2004, and below 400 kbpd in 2015.

Meanwhile, Australia’s oil consumption has steadily increased, from about 600 kbpd in the mind-1980s, passing 800 kbpd in the late 1990s and reaching about one million bpd early in the present decade. As a result, oil imports—which had barely exceeded 200 kbpd between 1971 and 2002—have steadily increased to just over 600 kbpd in 2015. Figure 7 presents the data on Australia’s production, consumption and net imports of oil (as crude and as refined petroleum products).

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Figure 7 Australia’s oil production, consumption and net imports, 1965-2015

Sources: Author’s calculations using data from the BP Statistical Review of World Energy, and The World Bank

Figure 8 Australia’s crude oil expenditure as share of GDP and Australian recessions

Sources: Author’s calculations using data from the BP Statistical Review of World Energy, 2016 and the Australian Bureau of Statistics. Note: Australian recessions are defined as two consecutive quarters of negative GDP growth

Australia benefited from significant offshore oil and gas discoveries in the late 1960s, of which oil was a major part. In contrast, Australia's more recent major oil and gas discoveries have tended to be gas-dominated. In the absence of major new commercial oil discoveries, sometime during the 2020s Australia’s oil supply and demand balance is likely to return to the situation before oil was discovered in Bass Strait.

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If large new commercially viable oil fields are not discovered and developed in Australia, then the country will become oil import dependent, and be in a similar situation to most of its neighbouring countries in the Asia Pacific region, and also much more like most of the other member countries of the IEA.

Given Australia’s low population density, the large distances between cities, and the heavy reliance on road transport for freight and passengers, it is perhaps surprising Australia’s spends a smaller share of GDP on crude oil than the world as a whole.9 Figure 8 shows how Australia’s crude oil expenditure at market prices has evolved over the 50 years to 2015.

Australia and has not spent more than 3.1 per cent of GDP on crude oil for the three decades since 1985. Due to local production, national expenditure on oil imports is smaller still: between 1 and 1.5 per cent of GDP, as was the case during the high oil price period from 2005 to 2014, a level similar to the oil import share of GDP between 1979 and 1983.

Although each country’s situation is unique, there are some common themes between oil importers. For example, Figure 9 shows the situation for the United Kingdom and Figure 10 shows the situation for the United States. The UK has experienced almost flat oil demand for 50 years, and oil consumption in 2015 was about the same level as in 1965. In the case of the UK, efficiency improvements and mode switching have together cancelled out underlying oil demand growth. The growth, plateau and decline of North Sea oil production have change the UK from a net oil importer to a net exporter then back to a net importer again.

Figure 9 United Kingdom’s oil production, consumption, net imports and exports, 1965-2015

Sources: Author’s calculations using data from the BP Statistical Review of World Energy, and The World Bank

The United States has been a net oil importer since well before 1965. However, after more than two decades of steadily rising oil imports as consumption grew and production fell, the trend reversed in the decade from 2005 to 2015, as consumption contracted, and then production surged.

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Figure 10 United States’ oil production, consumption and net imports, 1965-2015

Sources: Author’s calculations using data from the BP Statistical Review of World Energy, and The World Bank

These examples highlight that the status and ramifications of oil import dependency are not static, but can change very significantly and relatively quickly. However, ‘oil import dependence’ is only part of the picture. The other part of the picture is the dependence on revenues of oil exporters.

1.2.9. Oil export revenues and mutual inter-dependence between exporters and importers

For some OPEC members, oil and refined petroleum exports contribute the vast majority of their export income.10 Using the most recent available data from 2014, oil accounts for between 56 per cent and 99.8 per cent of OPEC members’ exports. Adding pipeline natural gas and LNG exports would further increase the share for many countries. Figure 11 shows the dependence on oil export revenues, measured as a share of all goods exports, versus annual export volumes. For illustrative purposes, the figure has been divided into four zones. Above and below 3 Mbpd of exports, and above and below 50 per cent oil share of national export revenues. For reference, supply disruptions globally (which are discussed further below) have been continuously between 2.5 and 3.5 Mbpd, averaging about 3 Mbpd since mid-2013. For most of the time from early 2011 to mid-2013, the disruption level was about 2 Mbpd. The disruptions have been offset, or more than offset by the increase in light tight oil (LTO) production in the United States since 2010.

From the perspective of intentional disruption, the highest risk countries would be those with large exports (defined here as greater than 3 Mbpd), and with oil revenues representing a small share of total export revenues (defined here as less than 50 per cent). It is notable that there are no countries in this category. In other words, oil exporters also lose from intentional disruptions to supply. Most OPEC countries are in the top-left area, with oil constituting most of their export revenues and being a small contributor to global exports. Only two OPEC countries (Saudi Arabia and Iraq) and Russia are above the 3 Mbpd export level. All three are heavily dependent on oil revenues for export income. Russia is the least dependent on oil revenue of any large exporter, and based on this analysis, presents a greater disruption threat than the OPEC countries. Europe has relied on oil imports from the Soviet Union and Russia since the 1960s. Historically, there were few, if any disruptions; of most note was the disruption of Russian oil supply to Europe in January 2007, during an oil pipeline transit dispute with Russia and Belarus (Deutsche Welle, 2007). Qatar is the only OPEC country with less than 50 per cent of export revenue from oil and refined products, and it exports less than 2 Mbpd. The other oil exporters in the lower left hand region of the figure are either OECD countries (Canada, Norway, Mexico), or non-OPEC countries.

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Figure 11 Oil export revenue dependence of selected key countries, 2014

Sources: Author’s calculations of exports using country oil production and consumption data from BP, Statistical Review of World Energy, 2016; country trade data from MIT, Observatory of Economic Complexity, http://atlas.media.mit.edu/en/

By any standard definition, OPEC collectively represents significant market concentration. However, the leverage that the concentration offers is reduced by the large number of members, and also by the fact that most members depend very heavily on oil export revenues. The growth in United States light tight oil production has not only counter-acted the global level of supply disruption since 2010, but it has also neutralised—at least for the time being—much of the leverage that would otherwise arise from the market concentration of OPEC producers.

1.2.10. The importance of viewing the oil market from multiple perspectives

A thorough understanding of the oil market requires good knowledge of the fundamentals of supply and demand, the range of factors that influence the economics of commodities. Those factors include:

geology and geography

the technology of exploration and production

probabilities and risk

substitutes including alternative energy sources and energy efficiency improvements through the technologies of energy conversion and utilisation

commerce and governance

banking, finance and the monetary system

national and international institutions, and

policy and legislation.

Many of these factors interact in complex ways, which contribute to the difficulty in understanding the oil market. Many oil market analysts, whether in government or the private sector, tend to view the oil industry from their own particular perspective. Even where analysts and experts endeavour to take multiple factors into account, and attempt to view the industry from more than one perspective, overlooking one of the factors from the list above is sometimes enough to compromise the analysis.

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Perhaps the classic example of the importance that analytical and professional perspectives play in oil market analysis is the ‘peak oil debate.’ ‘Peak oil’ may be characterised as a debate between geological and economic perspectives. Many geologists have tended to coalesce around the view that oil production will inevitably go into decline and the resource base will be depleted. Many economists, meanwhile, hold to the view that the physical resource is not a binding constraint and is never likely to be, due to the incentives provided by economic forces for technological and commercial innovation.

The peak oil debate centres on the ‘Hubbert curve’ or ‘Hubbert peak theory.’ Marion King Hubbert (1903-1989) was an American geologist and geophysicist at the Shell research laboratory in Houston, Texas who observed that the rate of petroleum production for any given geographical area tends to follow a bell-shaped curve. The application of this observation to the planet as a whole underpins Hubbert peak theory. Hubbert’s theory was successful in predicting the peak in United States oil production in 1970, and many oil producing regions can be cited where the production history fits well with the Hubbert curve. However, the recent surge in United States light tight oil (LTO) production through the ‘shale oil’ or ‘fracking’ revolution represents a departure from the curve.

The response of peak oil advocates is that shale oil represents a new category of resource, which itself exhibits the characteristic bell curve. Indeed, production from a number of the shale plays in the United States does appear to exhibit bell-curve characteristics. The critics of peak oil theory naturally tend to respond that the shale revolution is confirmation of the view that new resources will be forthcoming when needed, and that shale oil is a resource that—while known about for decades—very few people expected to be produced commercially in the foreseeable future as recently as 2005.

The shale oil revolution provides is a recent example of the risk of not taking into account multiple perspectives in viewing the oil market, and of under-estimating the significance of key factors: in this case technology and the commercial incentives of a period of high prices. Having missed the coming shale oil revolution ten years ago, there may now be a risk of over-estimating its effect on the market.

The peak oil debate is not merely an academic disagreement primarily based on different perspectives between geologists and economists. Whichever view prevails in government, particularly in Washington, but also in the major capitals of Europe, the Middle East, and increasingly in Asia, has a very real effect on policy, on legislation, on the strategic and tactical behaviour of national and international oil companies, and on markets. The role of policy and legislation is sometimes overlooked in oil market analysis. In other analysis, there is a focus on policy and legislation without adequately taking into account economics and the market. This paper attempts to balance the two.

1.2.11. The value of recalling historical context and lessons for the future

The dramatic events of 1973, and the rapid rise in United States crude oil imports in the early 1970s are widely known. What is less well-known is that as early as 1944 the United States was a net oil importer. By 1951 United States oil imports were approaching half a million barrels per day, and net imports over 400 kbpd:11

The booming United States petroleum industry reported yesterday that in 1951 it had met the greatest demand for its products in history with the greatest output of all time. But it also had to import more than it exported, to satisfy its customers. (American Petroleum Institute, 1951, as reported)

As Figure 12 shows, the trend of rising United States crude oil imports began in the late 1940s, and continued through the 1950s and 1960s, even as United States crude oil production grew strongly. However, it was the downturn in domestic production after 1970, combined with continued strong demand growth that led to the extraordinarily steep rise in United States crude oil imports during the 1970s.

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Figure 12 History of crude oil production, imports and exports in the United States, 1900-2015

Source: United States EIA data

Following the Arab Oil Embargo in October 1973, the United States passed the Emergency Petroleum Allocation Act (EPAA) in November. The chronology of events was very rapid indeed: a mere 42 days elapsed from OPEC’s unilateral raising of posted prices on October 16th, the day before the embargo was declared on October 17th to the signing into law of the EPAA by President Nixon on November 27th (the Appendix (section 6.1.2) contains a chronology of events leading up to and following the 1973 oil crisis). The EPAA was later extended by the Energy Policy and Conservation Act (EPCA) of 1975, providing the legislative basis for the United States Strategic Petroleum Reserve (SPR).12 Section 103 of the EPCA also established the ban on the export of crude oil (but not refined products) from the United States.13 As a self-sufficient producer-consumer, then a net importer, United States crude oil exports have never been substantial, as the EIA data in Figure 12 shows. Subsequently, on January 28, 1981, the EPAA oil price and allocation control regulations were withdrawn by Executive Order of President Reagan, shortly after his swearing in as President.14 The legislative ban on the export of crude oil remained in force until December 18th, 2015, when the United States Congress repealed §103 of the EPCA in its entirety.15

The EIA has published its own detailed Petroleum Chronology of Events 1970-2000 (EIA, 2002). It summarises the EPAA as follows:

The principal aims of the Emergency Petroleum Allocation Act (EPAA) were to ensure equitable distribution of available products, to establish equitable prices, and to preserve the independent segments of the oil industry. EPAA established a two-tiered pricing system for domestic crude oil. "Old" oil, designated as crude oil from properties producing at or below their 1972 production levels, was subject to a price ceiling while "new" oil, stripper oil, and "released oil" (added as an incentive for increased production from old fields) was allowed to be sold at market prices. The price of imported oil remained unregulated.

The cycle from the EPAA of 1973 to Executive Order 12287 at the beginning of 1981 does not necessarily reflect the cycle in the oil market from a tight/ sellers’ market to a loose/ buyers’ market: in 1980 the nominal oil price still averaged $36.83 per barrel, equivalent to $106 in 2015 terms. It was not until the following years that the price began to fall. Rather, the policy cycle reflects the shift in influence from the ‘peak oil’ school of thought that had prevailed through the Nixon, Ford, and Carter Presidential era (notably including both of the major United States political parties) to one based on the underlying economics, which coincides with the Reagan, Bush and Clinton Presidencies (again notably including both of the major political parties in the United States).

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The former school of thought is driven by concerns about depletion and the limitations of markets, and is mindful to use the levers of government to ensure secure supply. The latter school of thought tends to put greater faith in the ability of markets to ensure that supply and demand are balanced, at an efficient price.

Most people are somewhat familiar with the turmoil of the early 1970s in the monetary system, the oil market, and major power relations. It should not be forgotten that it was during the Cold War, and relations between the United States and the then Soviet Union could be diplomatically described as tense. Not only oil, but the Middle East as a region was of great interest for the major powers.

With respect to the importance of policy and legislation influencing the oil market (and vice-versa), it is worth looking back more than a decade before the 1970s to the Mandatory Oil Import Quota program (MOIP) of the United States, which began in 1959. Presidential Proclamation 3279 by President Eisenhower was intended to prevent a dependence of the United States on imported petroleum supplies. From 1962, the maximum level of imports was set at 12.2 per cent of domestic production. Zycher (2005) notes that:

Few observers and even fewer experts remember that the Organization of Petroleum Exporting Countries (OPEC) was created in response to the 1959 imposition of import quotas on crude oil and refined products by the United States. In 1959, the U.S. government established the Mandatory Oil Import Quota program (MOIP), which restricted the amount of imported crude oil and refined products allowed into the United States and gave preferential treatment to oil imports from Canada, Mexico, and, somewhat later, Venezuela. This partial exclusion of Persian Gulf oil from the U.S. market depressed prices for Middle Eastern oil; as a result, oil prices “posted” (paid to the selling nations) were reduced in February 1959 and August 1960.

In September 1960, four Persian Gulf nations (Iran, Iraq, Kuwait, and Saudi Arabia) and Venezuela formed OPEC in order to obtain higher prices for crude oil. By 1973, eight other nations (Algeria, Ecuador, Gabon, Indonesia, Libya, Nigeria, Qatar, and the United Arab Emirates) had joined OPEC; Ecuador withdrew at the end of 1992, and Gabon withdrew in 1994.

The collective effort to raise oil prices was unsuccessful during the 1960s; real (i.e., inflation-adjusted) world market prices for crude oil fell from $9.78 (in 2004 dollars) in 1960 to $7.08 in 1970. However, real prices began to rise slowly in 1971 and then increased sharply in late 1973 and 1974, from roughly $10 per barrel to more than $36 per barrel in the wake of the 1973 Arab-Israeli (“Yom Kippur”) War.

The quota program remained in place until April 18th, 1973, after which time it was abolished by President Nixon by proclamation and announced in his address to Congress on that day (Nixon, 1973). Quota limits on imports were replaced with a system to allocate imports and impose tariffs.16 As Yergin (1991, p.590) has observed, ‘Those two acts, coming one on top of the other, perfectly symbolized how circumstances had changed: Quotas were meant to manage and limit supplies in a world of surplus, while allocations were aimed at distributing whatever supplies were available in a world of shortage.’

The historical path from the import quota restrictions of the 1960s coupled with the regulatory management of United States domestic production to the imposition of supply allocations in the 1970s, as well as the imposition of the United States crude oil export ban in 1975 and its lifting in 2015, shows the importance of policy, legislation and regulation on the market. It also shows the influence that market conditions have had on policy, legislation and regulation.

Further discussion on the role and implications of policy–market interactions in the oil sector are addressed in later sections of this paper.

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Chapter 2. The Current State of the Oil Market

2.1. Key characteristics of the oil market today

2.1.1. Prospects, resources, exploration and reserves

Crude oil occurs in geological deposits around the world, both onshore and offshore. The most commercially attractive known oil fields are more geographically concentrated than is the case for natural gas or coal. BP reports almost 1.7 trillion barrels of proven oil reserves worldwide. Figure 13 shows the data for proven reserves of oil by region. The Middle East, with 800 billion barrels, accounts for almost half of the global proven reserves.

Figure 13 The geographic distribution of oil reserves

Source: Author’s chart using data from BP, Statistical Review of World Energy, 2016. Notes from BP: Total proved reserves of oil - Generally taken to be those quantities that geological and engineering information indicates with reasonable certainty can be recovered in the future from known reservoirs under existing economic and operating conditions. The data series for total proved oil does not necessarily meet the definitions, guidelines and practices used for determining proved reserves at company level, for instance as published by the United States Securities and Exchange Commission, nor does it necessarily represent BP’s view of proved reserves by country. The estimates in this table (used to create the chart) have been compiled using a combination of primary official sources, third-party data from the OPEC Secretariat, World Oil, Oil & Gas Journal and an independent estimates of Russian reserves based on official data and Chinese reserves based on information in the public domain. Canadian oil sands 'under active development' are an official estimate. Venezuelan Orinoco Belt reserves are based on the OPEC Secretariat and government announcements. Reserves include gas condensate and natural gas liquids (NGLs) as well as crude oil.

Data on proven reserves should always be treated with caution, for the reasons explained below. Worldwide data, such as those presented in the figure, are typically assembled from a number of bottom-up estimates, which typically do not all use the same assumptions.

Nevertheless, it is notable that, although significant volumes of oil are produced and consumed each year, the proven reserves have increased each year since 1980. Given that oil consumption is greater now than in the past, greater levels of reserves are required to sustain a given reserves-to-production (R/P) ratio. Conversely, if reserves are not increased by exploration (or re-estimating commercially recoverable volumes if prices rise), then the R/P ratio will fall as consumption increases.

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Figure 14 shows the R/P ratios for the major regions of the world from 1980 to 2015, and for the world as a whole. Throughout the 35-year period, the world R/P ratio has been between 40 and 60 years. At present, the global R/P ratio is at the lower end of that range. The R/P ratio is highest in the Middle East, which at current prices has 100 years of proven reserves at current at rates of production; Europe and Eurasia (largely due to Russia and the CIS), and North America, which each have about 60 years of proven reserves at current rates of production. Africa, Asia Pacific and Central and South America all have reserves equivalent to about 30 years of current annual production. While the R/P ratio is relatively low in those three regions, in each case, the present level is higher than in 1999, despite the significant growth in oil demand over that time period.

Figure 14 Reserves-to-production ratios by region and for the world

Source: Author’s calculations using data from BP, Statistical Review of World Energy, 2016

Throughout the past 35 years, the R/P ratio has varied widely in individual regions. The most dramatic example is the Middle East.17 Since 2000, the Middle East is the only region that has substantially grown its reserves relative to production, where the R/P ratio has increased from less than 50 years to 100 years. The reserves-to-production ratio for the world in 2015 was 44 years: similar to the ratio in 1980: 47 years, despite a 50 per cent increase in world oil production between 1980 and 2015. The data indicates that through exploration activity the industry ‘proves up’ from the underlying resource base sufficient additional reserves, well ahead of the time that those reserves are eventually brought into production.

The major step-change in the R/P ratios in Europe and Eurasia and North America in 1999 needs some explanation. The definition of reserves includes a commercial test or an economic test (Etherington, Pollen, and Zuccolo, 2005). That, in turn, requires an assumption about future prices, as well as an estimate of the costs of production for each field. Over time, exploration leads to new oil discoveries, which are added to reserve estimates. More seismic data is collected, which increases the quantum of prospective resources.

Estimating reserves across the portfolio of a company or a country is a substantial task. Therefore, although prices fluctuate continuously, the assumptions about future prices that are used to estimate commercial or economically recoverable reserves are usually only updated when expectations about future prices change significantly. Furthermore, the future price assumptions used for reserve estimates may be considered commercially sensitive and may not necessarily be disclosed. Whether disclosed or not, assumptions of future oil prices typically vary from one reserve estimate to another. A further complication is the fact that classifications and definitions vary from country to country, and the underlying

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methodology can also vary.18 All of those caveats need to be kept in mind when reviewing aggregate reserve estimates (such as those compiled and published by BP and used to create Figure 13 and Figure 14). Reserve estimates provide only a very approximate and general picture.

In the late 1990s, after nearly two decades of low prices, many future price assumptions were eventually revised, leading to a downward revision of reserve estimates. Middle East oil reserves estimates were initially revised downward in the early 1990s, and European and North American estimates (and Middle East estimates a second time) in the late 1990s. It is important to recognise that, throughout major reserve adjustments, the oil in the ground does not change and the oil produced and consumed represents a small fraction of reserves, considerably smaller than the adjustments to reserve estimates due to changes in assumptions about future prices. Advances in technology increase the oil that can be considered commercially recoverable in the future.

Figure 16 provides a useful picture of the three major categories of resources and reserves: undiscovered, discovered sub-commercial and discovered commercial. ‘Reserves’ refer to ‘discovered commercial’ oil. Within reserves there are proven ‘1P,’ plus ‘probable’ ‘2P’ plus possible ‘3P’ reserves. Proven reserves are generally defined as having a 90 per cent probability (P90), probable as a 50 per cent probability (P50) and possible as a 10 per cent probability (P10).

Figure 15 Project status categories and commercial risk

Source: Etherington, Pollen, and Zuccolo, (2005), of the Society of Petroleum Engineers, Figure 4, p.28.

If the price assumption is changed, the boundary between ‘discovered commercial’ and ‘discovered sub-commercial’ will shift. When the assumption of future prices is revised downward, some projects that were planned for development may move down to the ‘development pending’ category, or to ‘development on hold’ or even to ‘development not viable.’ That is what happened to many conventional oil projects after the collapse in oil prices from 2014 to 2015, and also explains the reduction in the number of active drilling rigs in the United States from almost 2000 in late November 2014 to just over 400 by February 2016. The vast majority of those rigs are onshore horizontal drilling rigs targeting shale oil: that subset of the total rig count collapsed from more than 1500 to almost 300.

2.1.2. Exploration and production technology, costs and the price cycle

The oil industry is one of the most technically sophisticated industries in the world. Potential oil deposits are identified using sophisticated three-dimensional (3-D) spatial seismic imaging, and the performance of producing fields is monitored using four-dimensional (4-D) time-lapse spatial seismic imaging. Oil reserves

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are ‘proven’ and recovered from fields by drilling through rock for up to 10,000 metres (35,000 feet) or more and in water depths of up to 3,000 metres (10,000 feet) or more.

The capital of a single exploration well can range from tens of millions to hundreds of millions of US dollars. United States offshore developments in the Gulf of Mexico provide a point of reference: ‘In a nutshell, the overall drilling and completion costs at normal reservoir and well conditions are estimated between $60 [and] $240 [million] for wells in water depths from 7,500 feet to 15,000 feet.’19

High prices contributed to stimulating a technological revolution that combined directional horizontal drilling with hydraulic fracturing or ‘fracking’ and applied it to onshore oil resources in the United States. Low interest rates encouraged development of the industry, and many shale producers are highly leveraged. Known oil resources in shale beds that were previously considered uneconomic became commercially recoverable and were brought to market. Innovation led to further cost reductions as oil prices declined.

In the past decade, the capital costs of developing upstream oil projects more than doubled, with most of the increase occurring between 2005 and 2008. More recently costs have declined, but not down to their previous level, as shown in Figure 16, which is(derived from a widely-referenced industry cost index (IHS Energy).

Overlaying a crude oil price index to the industry cost index leads to a number of observations.

The first observation is that price levels do influence industry costs, with a lag of about a year. This suggests that the cause-effect linkage was from increased demand to increased prices to increased costs, which is consistent with what we know. Further analysis in section 3.7.2 below shows that there was also a monetary aspect to the increases.

The second observation is that when the market tightened on this recent occasion, costs did not increase to the same extent as prices. As the second chart in Figure 16 shows, costs more than doubled, but prices quadrupled.

The third observation is that there is some asymmetry between the up-cycle and the down-cycle. When prices fell, in 2009 and in 2015, the industry made productivity improvements, but costs did not fall to the same extent as prices. This phenomenon is often referred to as the ‘stickiness of costs.’ One explanation is that the increase in demand has moved the industry to a higher cost level than before.

Price volatility and future price uncertainty are indicative of the risk that is an oil industry characteristic. The sensitivity of capital costs to prices is part of the risk equation, along with interest rates and interest rate expectations. Figure 16 can be viewed as showing the market in action, working as it should: higher prices signal that more supply is needed to meet demand, and that the market is willing to pay higher prices for it. Supply responds, bringing on new supplies at higher costs than would have been contemplated before the price rise. The arrival of new supplies (with the slight over-correction common in markets) brings down the prices, leading to a drive to compress costs for production to remain competitive and for companies to remain in business.

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Figure 16 Indices for the capital costs of upstream oil production and oil prices

Source: www.ihs.com/info/cera/ihsindexes/ and www.eia.gov/dnav/pet/pet_pri_spt_s1_d.htm

2.1.3. Relationships between prices and costs and between oil and other commodity prices

As highlighted above, oil exploration and production is very capital-intensive. Figure 17 provides an example of the typical cost structure of conventional oil production, showing large up-front capital costs, and proportionately small annual operating costs. The first phase of drilling is used to ‘prove up’ the ‘P90’ reserves, providing a 90 per cent probability that there are sufficient reserves to justify investment in production. With the production volume risk thus reduced, capital investment is made in preparation for production drilling. As production wells are drilled and completed, production volumes ‘ramp up,’ in this example over three years, until a plateau of production is reached, which in this example is sustained for 16 years. Additional compression in this example is added in the 11th year to offset the decline in the pressure of the field. At the end of the plateau, the field enters its decline phase.

While the profile of production volumes has a predictable characteristic shape, the revenue stream does not, because the production volumes need to be multiplied by the prevailing market price, which tends to be volatile. If a producing oil field received a constant price for its production, the shape of the revenue profile would be identical to the shape of the production profile. Figure 17 provides an illustrative example of the

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effect of volatile prices in transforming the production profile into the revenue profile. For the purposes of this example, inflation-adjusted oil prices from 1981 to 2015 were used; the exploration drilling began in 1976, following the price spike of 1973-74, and development was completed from 1978 to 1980. So the capital expenditures happened to coincide with the very high oil prices of 1979 and 1980, but no revenue was earned in those years. As the revenues began to flow from 1981 (production year one), the oil price happened to fall, and continued to do so throughout the 1980s and 1990s. By the time oil prices rose again in the 2000s, the field was mature and production was in decline, although the oil price rises helped to offset the production declines.

While the numbers behind Figure 17 are purely hypothetical, the general pattern shown would be not unusual for offshore developments in the North Sea following the oil crises of the 1970s.

Figure 17 Example of typical capital cost, operating cost and production profile for conventional oil

Source: Author’s chart, using hypothetical data typical of a conventional offshore oil and gas development

The cost of oil and gas production is a function of the various input costs, which include steel, drilling and oilfield services, rig rates, engineering expertise and skilled labour. Figure 18 shows the relationship between monthly average Brent crude oil prices and monthly prices for European hot rolled coil steel.

IEA (2013a) notes industry-specific inflation as a factor in the dynamic interaction of costs and prices:

…the period 2000-2008 clearly showed that, as an increasing oil price pushes up industry activity levels, so increasing supply and service costs also drive up capital and operating costs. The correlation between oil prices and industry costs observed during that time period is encapsulated in the WEM, so that higher oil prices lead to higher costs. Some may argue that the 2000-2008 period was atypical, as the supply industry had to build-up very quickly after a decade of relatively low activity, leading to price tensions. However it is reasonable to expect that all industry participants (producers, supply and services companies, and governments awarding the licenses and imposing various production taxes) will always try to capture their share of higher oil prices, de facto pushing costs up proportionally. (p.454)

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Figure 18 Example of the cross-commodity relationship between oil and steel prices

Source: Author’s chart using data from MEPS and oil price data from the EIA

Now that the oil market has turned from a tightening phase to a loosening phase, and the price cycle has turned from the phase of rising and high prices to falling and low prices, the industry has moved from experiencing cost escalation to cost compression.

2.1.4. Risk, financing and investment

Exploration and production of oil involve significant technical and commercial risk. This risk is shared between host governments and oil companies throughout each stage of development from exploration to production. Many governments provide pre-competitive geological studies, which can play an important role in attracting the interest of oil companies to bid for exploration licenses. If companies perceive that the potential returns are not sufficient to justify the risk they will not invest in exploration or production. The risk-return equation is materially affected by expectations of future prices. Risk at the project level is typically managed by companies ‘farming out’ or ‘farming in’ to developments with partner companies, to achieve a more diversified portfolio of development, production and country risk than would be possible with single company investments.

2.1.5. Royalties, excise and taxes

On the upstream side of the industry, the host governments of oil developments receive a share of the available natural resource rent. The lower the underlying costs of production, the higher the natural resource rent, and vice-versa. The details of International Petroleum Agreements (IPAs) vary, but modern IPAs are generally either production-sharing contracts or modernised concession agreements with a greater degree of host government control over petroleum operations and state participation than was the case with the original concession agreements (Duval 2009b).

Taxes, excise and royalties on the downstream side dampen the translation of crude oil prices through to refined product retail prices, reducing the elasticity of crude oil price demand, as discussed in section 2.1.15 ‘Demand, prices and price formation’ on page 34.

2.1.6. Production capacity

The oil industry cost structure is dominated by large, up-front capital costs. One result of this cost structure is that once a capital investment decision has been made there is a strong commercial imperative

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to produce oil at full production capacity, subject to geological and technical constraints. The maximum rate at which oil can be produced from a well or a matrix of wells in an oil field without damaging the structure is strongly influenced by the field’s geological characteristics, including the permeability of the host rock. The normal approach to selecting the production capacity of a development involves maximising the present value of the investment, which usually involves a trade-off between high production rates in the early years, and maximising the productive life of the field.

Price risk is an important factor in this optimization process, which the example of Figure 17 illustrates well. If the decision was made to invest in a lower production capacity, the up-front capital costs would be lower, but the unit cost of production would be higher compared to those for a higher production capacity. However, the present value of the revenue stream would be reduced for two reasons. The arithmetic of discounting reduces the present value production in later years far more than production in early years. If prices do happen fall after the initial investment is sunk (which is the case in the example, using actual prices from 1981 to 2015), then it is preferable to have as much production as possible in the early years when prices are higher. In a case when prices rise, the opposite may be true, particularly if prices increase faster year-on-year than the annual discount rate used. However, more investment in new production naturally tends to be made during, or immediately following times of high prices, and fewer investments tend to be made during, or immediately following times of low prices. The logic goes a long way to explaining the commodity price cycle.

Production capacity, spare capacity and production flexibility are important considerations in the oil market. They are discussed further in the context of OPEC capacity and quotas under ‘OPEC quotas and oil production’ in section 2.2.5.

2.1.7. Supply, market share and competition

Figure 19 shows the market shares of global oil production for the five largest oil producing countries, and for major groupings: OPEC, Middle East, North America (the United States, Canada and Mexico) and Europe and Eurasia (which includes the EU, the Russian Federation and the CIS).

The three biggest producers in 2015 were the United States (14 per cent), Saudi Arabia (13 per cent) and Russia (12 per cent). The fourth and fifth largest oil producers, Canada and China, are a long way behind, accounting for slightly less than 5 per cent of global production.

OPEC’s oil production is more than 40 per cent of world supply. The Middle East (which includes some non-OPEC countries such as Oman, Syria and Yemen) is about one-third of global supply. North America and Europe and Eurasia each account for about 20 per cent of global oil production. In recent years, North America has increased from about 16 per cent to over 20 per cent while production from Europe and Eurasia has decreased from nearly 22 per cent to 19 per cent.

From the mid-1970s to the early 1980s, the USSR increased its share of world production from about 15 per cent to well in excess of 20 per cent. Following the collapse of the Soviet Union, the Russian Federation share of production declined to below 10 per cent, before recovering to about the current level in the second half of the 1990s.20

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Figure 19 Market shares of global oil production, 1965-2015

Source: Author’s calculations using data from BP, Statistical Review of World Energy, 2016

2.1.8. Logistics and supply chains from well to wheels

Figure 20 provides a high-level overview of the ‘well-to-wheels’ oil value chain from exploration and investment in production, pipeline and tanker transport to refining, distribution, sales and marketing and final consumption where the energy conversion and utilisation delivers the final service, such as transportation.

Figure 20 High-level overview of the oil value chain

Source: Author’s calculations using data from BP, Statistical Review of World Energy, 2016

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The value chain is very capital-intensive, particularly at the upstream end, and entails a high degree of commercial risk, particularly at the exploration stage, where wells drilled into target structures may turn out not to bear commercially viable quantities of hydrocarbons.

The value chain is heavily dependent on physical logistics. Infrastructure in the form of offshore and onshore pipelines and ocean-going tankers, as well as rail and road transport is essential to link producing fields to refineries and refineries to customers.

2.1.9. Inventory, commercial storage and strategic reserve stockpiles

In addition to the transport infrastructure, the value chain includes some storage, of both crude oil upstream of refineries and of refined products downstream of refineries. To optimise capacity along the value chain, and for economic efficiency generally, the industry tends to keep inventory levels as low as possible, typically in the order of one week to one month. Strategic reserve stockpiles increase the level of stocks in the system above the optimal commercial levels under normal conditions.

2.1.10. Imbalances between production and consumption and the economics of oil trade

Figure 5 on page 9 shows the share of global crude oil trade by import destination and Figure 6 on page 10 shows the share of global crude oil trade by export origin. Figure 21 builds on these further to show production, trade and consumption of crude oil globally. The oil-long OPEC countries are shown in the lower part of the figure and the oil-short OECD countries in the upper part. In between are the non-OPEC, non-OECD countries, which increasingly account for a large share of oil imports. It is noteworthy that Australia’s share of the market is so small as to be almost invisible on the chart.

Figure 21 Visualisation of global oil production, trade and consumption, 2014

Source: Author’s chart based on calculations from the BP Statistical Review of World Energy, 2015

The imbalances between production and consumption across countries are the main reason that the physical market in internationally traded oil is so large. The second reason is that the cost of long-distance transport and storage of oil is very small relative to the value of the commodity. This makes trade on a global scale economically worthwhile: it is more economic to import oil that can be produced at low cost than developing high cost domestic oil fields.21 The third reason for large-scale oil trade is that quality and characteristics vary significantly from one grade of crude oil to another, whereas refineries tend to be configured to process crude oils with a narrower range of characteristics. Therefore, particular types of oil

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need to be supplied to where they can be blended or refined into the required product for ultimate consumption. Hence, oil trade is driven not only by differences between total production and consumption quantities, but also by differences in characteristics and the associated intended use of the oil. Trading and blending allows the range of crude oils produced around the world to be matched with the capabilities of individual refineries and finally with levels of demand for the variety of petroleum products in each market.

2.1.11. International trade flows of oil and refined products

In 2015, two billion tonnes of crude oil and one billion tonnes of refined products were traded between regions.22 Over half of global crude oil was imported to the Asia Pacific region (Australasia, China, India, Japan, Singapore and other Asia Pacific), as well as 44 per cent of refined products. Within the Asia Pacific region there is limited trade in crude oil and refined products and most of the crude oil exported by Asia Pacific countries remains within the region (47 of 50 million tonnes). A similar pattern is true of refined products (236 of 305 million tonnes). The data paints a picture of Asia Pacific as the world’s largest oil-short region.

The three largest oil-exporting regions—the Middle East, Russia and West Africa—account for well over half of global crude oil exports. Adding South and Central America means the top five crude oil exporting regions account for over 80 per cent of world exports by tonnes.

In refined products, the United States is the largest exporter, followed by Russia and the Middle East. Together the top three account for almost half of global exports in refined products. Adding Europe, Singapore, India and China brings the total close to 80 per cent of global refined product exports.

On the import side, Europe was the largest importer of crude oil in 2015, followed by the United States and China, collectively accounting for more than half of global imports. Adding India, Japan and Singapore accounts for more than 80 per cent of crude oil imports. (Singapore is a regional refining hub, with a small domestic market). Europe is also the largest importer of refined products, ahead of Japan and the United States, which collectively account for about 40 per cent of global imports.

Table 2 summarises the major patterns of trade flows globally for crude oil and refined liquid products as percentage shares of the totals. The physical quantities are shown in the Appendix in Table 14 on page 136. In 2015, two billion tonnes of crude oil was traded, plus one billion tonnes of refined products, for a total of three billion tonnes of liquids.

The following major patterns are apparent in the data:

Imports to the Asia Pacific region account for half of the market in crude oil and total liquids.

Exports from the Middle East to Asia Pacific account for one-third of global crude oil trade.

Exports from the Middle East to Asia Pacific account for one-quarter of liquids trade.

Trade within the Americas accounts for 15 per cent of global trade.23

Trade between Europe, Russia and the CIS accounts for 12 per cent of global trade.

Within Asia, China, India and Japan account for more than one-third of global oil imports.24

China, India and Japan are also major refiners and exporters of refined products.25

Adding Singapore accounts for almost one-fifth of global refined product exports.26

Table 2 Summary of crude oil and refined product trade flows, share of total, 2015

Crude oil per cent of 1977 Million tonnes

To Americas EU-Rus-CIS Middle East Africa Asia-Pacific

SUBTOTALS

From

Americas 15 2 < < 5 21

EU-Rus-CIS < 12 < 0 5 17

Middle East 4 5 - 1 34 44

Africa 2 7 < - 6 14

Asia-Pacific < < < < 2 3

SUBTOTALS 21 26 0 1 52 100

Refined liquid products per cent of 1029 Million tonnes

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To Americas EU-Rus-CIS Middle East Africa Asia-Pacific

SUBTOTALS

From

Americas 16 4 < 1 5 26

EU-Rus-CIS 5 11 2 4 6 28

Middle East 0 2 - 2 10 14

Africa 1 1 < - 1 3

Asia-Pacific 2 2 2 1 23 30

SUBTOTALS 25 19 4 8 44 100

Total crude oil plus refined products per cent of 3006 Million tonnes

To Americas EU-Rus-CIS Middle East Africa Asia-Pacific

SUBTOTALS

From

Americas 15 2 < < 5 23

EU-Rus-CIS 2 12 1 2 5 21

Middle East 3 4 - 1 26 34

Africa 1 5 < - 4 10

Asia-Pacific 1 1 1 < 9 12

SUBTOTALS 22 24 1 3 49 100

Source: BP, Statistical Review of World Energy, 2016. “<” means less than 1; “-“ means zero or not applicable

2.1.12. Physical and financial markets

Physical oil is transported via pipeline and tankers, and trading is underpinned by a sophisticated financial market. Financial arrangements include term contracts and spot trades. Buyers and sellers can choose to hedge prices using financial derivatives (for example, futures and options).

The market for internationally traded ‘physical’ oil represents about half of global oil production and consumption, and oil represents the largest physical balancing market in the world. The markets that trade financial contracts based on oil are the largest commodities ‘paper’ markets in the world. Figure 22 provides a representation of the various physical and financial markets and interactions between them.

Refined product markets can influence crude oil markets, but the main direction of influence is from crude oil to product markets. Crude oil, condensate and natural gas markets also interact with each other.27 Oil forward markets, futures markets and OTC derivatives markets are financial markets and interact with the money market, the bond market, equity markets and currency markets.

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Figure 22 The interconnections between physical and financial markets for oil

Source: Author’s chart, adapted from Luciani (2010).

2.1.13. Storage, trading, futures, derivatives and the ‘paper oil’ market

Oil is priced in US dollars, which functions as the ‘vehicle currency’ for international oil trade, as it does for natural gas, thermal and metallurgical coal, iron ore, copper, aluminium and practically all internationally traded commodities.28

When commodities are traded between countries other than the United States, two foreign currency transactions will typically be required in an oil trade: one on either side of the US dollar oil trade. Banks also play numerous other roles in facilitating trade beyond foreign currency transactions. Through their currency trading desks, banks and trading houses add depth and liquidity to the paper market in oil derivatives.

Physical storage plays a role not only in the end-to-end production-refining-consumption physical logistics chain, but also as part of the linkage between the physical and financial or paper markets. The economics and financing of storage connects spot prices with futures prices. On any given day, oil traders will be actively seeking out and trading away opportunities to arbitrage the price of oil based on prices along the forward curve (which prices oil for delivery at specified future dates – see Figure 23), the cost of oil storage, the cost of oil transportation to storage facilities, and interest rates.

There are several types of physical oil storage, including above-ground tanks, underground caverns and tankers or ‘floating storage.’ Strategic oil stocks maintained by governments and by companies on behalf of governments does not participate in the linkage between physical and financial markets as commercial storage does, but the release of strategic oil stocks will naturally affect the market.

The shape of the forward curve on any given day is referred to as either being in ‘contango’ or ‘backwardation.’ The sample day in Figure 23 shows the forward curve in contango, meaning that the futures price is higher than that day’s spot price. When the futures price is lower than the prevailing spot price, the forward curve is in backwardation.

Contango encourages the buildup of physical stocks. The standard trading strategy in response involves buying spot and selling futures for the traders’ required return after covering the cost of storage and financing. Backwardation encourages financial commodity investors. The standard trading strategy involves selling spot and buying futures. A contango occurs when the market expects future prices to be higher than today’s price. Normally, a contango occurs when the prices for the nearest delivery

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month are low and conversely, backwardation occurs when the price for the nearest delivery month is high. Backwardation is the “normal state” of a market because holding stocks has a physical and financial cost via the interest rate (Luciani, 2010, p.57).

The forward price signals provided by the paper markets, and the ability of both producers and consumers to hedge their price risk, enable far more sophisticated risk management capabilities than were available before these markets were developed.

2.1.14. The size of the paper markets in oil

The open interest in Brent Crude oil futures contracts on 14 August 2016 was 2.22 billion barrels on contracts from October 2016 to March 2023, with about 80 per cent of the open interest in contracts within the 12-month window. The open interest is equivalent to about 23 days of global oil production and consumption, or about 45 days of global physical trade. The daily traded volume was 15 million barrels: less than one per cent of the open interest, or about one-sixth of global daily physical consumption, or about one-third of global daily exports and imports. Figure 23 shows the forward price curve of Brent Crude Oil futures on 14 August 2016 and the open interest in contracts.

Figure 23 A snapshot of the Brent Crude Oil futures market

Note: Each contract (the minimum tradable size) is 1000 barrels Source: Wall Street Journal, online market data, available by subscription at quotes.wsj.com/futures accessed 16 Aug 2016

The open interest in West Texas Intermediate (WTI) futures contracts on the same day was 1.89 billion barrels, on contracts from September 2016 to December 2024, with 82 per cent of the open interest in contacts within the 12-month window. The open interest is equivalent to almost 150 days of United States oil production or almost 100 days of United States oil consumption or about 20 days of global oil production and consumption. The daily traded volume was for contracts equivalent to just under 30 million barrels: 2.5 days of United States production, 1.5 days of United States consumption, or two-thirds of global export-import oil trade or almost one-third of global production and consumption.

Adding together the volume of paper oil trading in Brent and WTI futures, on the sample day there was open interest in contracts equivalent to 4.1 billion barrels of oil. That is equivalent to 43 days of global oil production and consumption or about 90 days of global export-import oil trade.

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The undiscounted stock value of the futures markets (contract settlement prices multiplied by the open interest on each of the monthly contracts) on the sample day was $112 billion for Brent futures and $91 billion for WTI futures, for a total of $203 billion. The options market is additional to that.

The paper markets in crude oil are among the deepest and most liquid markets in the world.

2.1.15. Demand, prices and price formation

Oil demand is dominated by land, sea and air transport. The crude oil market is global and the law of one price applies. Particular crude oils vary in quality, and are subject to price adjustments relative to the benchmark price. Oil transport costs represent a very small proportion of the final delivered cost.

Oil prices are formed in a large, deep, liquid international market, which continually balances supply and demand. There are several benchmark spot prices, the most widely quoted being Brent blend in the North Sea, West Texas Intermediate at Cushing Oklahoma in the United States, and Dubai Crude in the Middle East. OPEC uses a Reference Basket of crude oils, Bonny Light is used in Nigeria, and Tapis Crude is traded in Singapore, a major crude oil import, refining and export hub in Asia.

The cost of refining crude oil to final products is not a major part of the value chain. In most countries, taxes constitute a very large proportion of the final price paid for oil products. For this reason, and depending on how the taxes are calculated, doubling or halving of the international price of crude oil does not necessarily translate to doubling or halving the final price of oil products. Supply-demand fundamentals and the volatile dynamics of oil price-formation are discussed in more detail in section 2.2.11.

2.1.16. Competing fuels

Oil products compete at the margin with natural gas, and with electricity. This competition is, however, relatively limited, with the dominance of oil in the transport market a key reason. The share of natural gas vehicles (LNG and CNG) remains limited. Likewise, electric vehicle market penetration remains small globally. Outside the transport sector, oil globally has a small share of the markets for electricity generation, heating and industrial applications.

Figure 24 Global shares of oil and other fuels, 2015

Source: Author’s calculations based on BP, Statistical Review of World Energy, 2016

Electricity is an energy carrier, not a source of primary energy. Hence competition for oil from electricity is actually competition from gas, coal and non-fossil fuels including nuclear power and renewable energy, depending on the characteristics of the relevant electricity grids.

Figure 24 shows that oil globally accounts for one-third (33 per cent) of primary energy use, ahead of coal (29 per cent) and natural gas (24 per cent). All non-fossil fuels combined (nuclear, hydropower, wind power, solar energy, biomass, geothermal and other sources) account for 14 per cent. Non-commercial biomass (animal dung, firewood and charcoal) is not included in these numbers.

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2.1.17. Energy technologies

Energy technologies are continually evolving, on both the supply side and the demand side, from upstream production of primary energy, through storage, transmission and distribution, to refining, conversion and final use. Technological evolution applies to oil and to other energy sources and pathways. On the demand side, the major technologies using oil products are the internal combustion engine in vehicles and the gas turbine in aircraft. Boilers for power generation, industrial applications and space heating may also use fuel oil, but the use of oil-fired boilers has declined since the 1970s, being replaced by natural gas where piped gas supply is available.

Since the 1970s, government policies from Japan to Europe to the United States have encouraged or mandated technologies that use energy, including oil, more efficiently. With the cumulating effect of technological improvements year by year, the energy efficiency of engines, turbines and boilers has improved enormously in the past four decades.

Technology revolutions have proved more challenging in the transport sector. Incremental improvements in the incumbent technology have so far kept the internal combustion engine well ahead of its challengers. Improvements include cost reductions through design, weight and material savings, together with efficiency improvements and emission reductions as well as reliability improvements, which are reflected in the much longer warranties offered by car manufacturers (for example 5 years or 100,000km) than were common several decades ago. Gasoline spark-ignition engines and diesel compression-ignition engines have a number of other very significant advantages of incumbency that present major hurdles for the alternatives. These include: a vast network of filling stations in every country of the world; long range between refilling; very short time to fill the tank; capital and operating cost affordability, even including the provision of large streams of government revenue in many countries in the form of fuel taxes; an extensive service network of dealers and mechanics familiar with the large installed base of technology.

The alternate technologies include compressed natural gas (CNG) and liquefied natural gas (LNG) vehicles, hydrogen fuel cell vehicles and battery electric vehicles. CNG and LNG vehicles have made some inroads among large vehicles, urban buses and heavy haul trucks on regular routes (including in China) where few filling stations are needed. Hydrogen fuel cell vehicles are still a long way from viability and are far from challenging the incumbent technology on any of the above criteria.

Battery-electric vehicles have made significant advances, and are commercially available in a range of formats, from small city runabouts to the glamorous two-seater sports cars, prestigious saloons and sport utility vehicles manufactured by Tesla Motors in the United States. The key advantage of battery-electric vehicles is their ability to plug into the existing grid at low incremental cost. Recharging an electric car in the garage at home overnight (on a low cost off-peak tariff) is naturally an appealing prospect for consumers. Electric vehicles are also quiet, and can accelerate to match a very expensive high performance supercar. However, on all of the other criteria noted above, they are still well behind internal combustion engine vehicles, most notably in terms of cost, and require government subsidy support in contrast with incumbent technologies that currently provide a stream of fuel tax revenue. The decline in oil prices has further increased the challenges for electric vehicles. However, technical improvements and cost reductions are expected to continue. If oil prices return to recent high levels, the economics will change again, and may accelerate the uptake of this technology.

2.2. The market, the economy and international institutions

2.2.1. Geographic distribution and the replacement of oil reserves

While Figure 14 on page 21 shows oil reserves by region, Figure 25 shows the sovereign control of oil reserves, grouped by OPEC, countries of the Middle East, OECD countries and other (non-OPEC, non-OECD) countries. The dominance of OPEC and the Middle East in oil reserves is very pronounced. However, the chart of reserves-to-production (R/P) ratio in Figure 26 reveals a rather different picture of reserves. The Middle East, OECD countries and other countries that are not members of OPEC or the OECD have collectively between 80 and 100 years of reserves at current rates of production. OPEC as a whole has barely 25 years of reserves at current rates of production. Given the high reserve ratio in the Middle East, and the fact that most Middle Eastern oil producers are OPEC members, this indicates that reserves are low in non-Middle Eastern OPEC countries relative to OPEC.

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Given an R/P ratio of 80 to 100 years, OECD countries, Middle East countries and other non-OECD and non-OPEC countries are producing between one and 1.25 per cent of their proven reserves each year. In contrast, OPEC countries outside the Middle East are producing about four per cent of their proven oil reserves each year.

2.2.2. Market structure: the major players in the physical oil market

Oil and gas producing companies are usually grouped as national oil companies (NOCs), international oil companies (IOCs) sometimes referred to as the ‘majors’ or ‘super-majors’ and the smaller ‘independents.’ The twenty-one largest oil and gas companies in the world are comprised of six IOCs and fifteen NOCs. The largest IOCs are: ExxonMobil, BP, Chevron, Shell, Total and ConocoPhillips. The NOCs are generally larger than the IOCs. In 2014, seven NOCs ranked above the largest IOC in liquids production. Saudi Aramco, Rosneft of Russia, Kuwait Petroleum, NIOC of Iran, Pemex of Mexico, the Abu Dhabi National Oil Co and PetroChina each produced more liquids than ExxonMobil, the largest IOC.

Control of oil production is shifting from IOCs to NOCs. In 2014, the fifteen NOCs collectively produced over 60 million barrels of oil equivalent per day (Mboepd) of liquids and gas in a global market of about 150 Mboepd.29 In 2014 the six IOCs produced 20.1 Mboepd. In the decade to 2014, the largest NOCs grew their production by over 10 Mboepd or 21 per cent, while the IOCs grew their production by only 1.4 Mboepd or 7 per cent.

Of the 80 Mboepd produced by the 21 largest companies, 51 was liquids and 30 gas. Of the 60 Mboepd produced by NOCs in 2014, about 40 was liquids and 20 gas. Of the 20 Mboepd produced by the IOCs in 2014, about 12 was liquids and 8 was gas.

Table 3 lists the 21 companies from the largest liquids producer to the smallest. Rosneft alone is the second-largest liquids producer in the world. The other two large Russian state-owned oil and gas companies have been grouped together with Rosneft. Statoil of Norway is 70 per cent state-owned, 30 per cent investor-owned, and hence is grouped with the NOCs.

Of the 15 largest NOCs, eight are from OPEC member countries. Between them, they account for just over half of the 2014 oil and gas production, but with 76 per cent of production in liquids, they account for 63 per cent of liquids production among the NOCs and half of all liquids production by the top 21 companies. In the decade to 2014, half of the growth in oil and gas production was from these eight NOCs in OPEC member countries.

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Figure 25 Sovereign control of oil reserves

Source: BP, Statistical Review of World Energy, 2016

Figure 26 Reserve production ratios

Source: BP, Statistical Review of World Energy, 2016

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Table 3 The world’s largest oil and gas producing companies

rank Mboepd 2014 share Mboepd rank Mboepd Mboepd 10-years

Group O+G Company Country (bold: OPEC) 2004 2014 Liquids 2014 Liquid

s 2014 gas Growth %

NOC 1 Saudi Aramco Saudi Arabia 10.8 12.0 87% 10.4 1 1.6 1.2 11%

NOC 5 Rosneft 0.3 4.7 82% 3.9 2 0.8 4.4 1467%

NOC 16 Lukoil Russia 1.9 2.3 84% 1.9 13 0.4 0.4 21%

NOC 2 Gazprom 9.8 8.3 6% 0.5 21 7.8 -1.5 -15%

NOC 3 National Iranian Oil Co Iran 5.1 6.0 52% 3.1 4 2.9 0.9 18%

NOC 10 Kuwait Petroleum Corp Kuwait 2.5 3.4 92% 3.1 3 0.3 0.9 36%

NOC 9 Petroleos Mexicanos Mexico 4.1 3.6 75% 2.7 5 0.9 -0.5 -12%

NOC 12 Abu Dhabi National Oil Co United Arab Emirates 2.0 3.1 85% 2.6 6 0.5 1.1 55%

NOC 6 PetroChina China 2.6 4.0 63% 2.5 7 1.5 1.4 54%

IOC 4 ExxonMobil International /US 4.6 4.7 51% 2.4 9 2.3 0.1 2%

IOC 7 BP International /UK 3.9 3.7 65% 2.4 8 1.3 -0.2 -5%

IOC 11 Chevron International /US 3.1 3.3 66% 2.2 10 1.1 0.2 6%

NOC 18 Iraq Ministry of Oil Iraq 2.0 2.1 98% 2.1 11 0.0 0.1 5%

NOC 14 Petrobras Brasil 1.5 2.4 85% 2.0 12 0.4 0.9 60%

NOC 19 PDVSA Venezuela 2.0 2.0 94% 1.9 14 0.1 0.0 0%

IOC 8 Royal Dutch/ Shell International /UK 3.9 3.7 47% 1.7 15 2.0 -0.2 -5%

IOC 13 Total International /France 2.6 2.5 50% 1.3 16 1.3 -0.1 -4%

NOC 21 Statoil Norway 1.7 2.0 59% 1.2 17 0.8 0.3 18%

IOC 20 Conoco Phillips International /US 1.8 2.0 58% 1.2 18 0.8 0.2 11%

NOC 17 Sonatrach Algeria 2.6 2.2 50% 1.1 19 1.1 -0.4 -15%

NOC 15 Qatar Petroleum Qatar 1.2 2.4 31% 0.7 20 1.7 1.2 100%

NOC subtotal 15 companies 50.1 60.5 66% 39.8 n/a 20.7 10.4 21%

…of which OPEC 8 companies 28.2 33.2 76% 25.1 n/a 8.1 5.0 18%

IOC Subtotal 6 companies 18.7 20.1 60% 12.1 n/a 8.0 1.4 7%

All TOTAL 70.0 80.4 63% 51.0 n/a 29.4 10.4 15%

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Source: Data from Wood Mackenzie, as published by Forbes. 30

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2.2.3. How the role of swing producer has evolved over time

The three largest oil-producing countries in the world are the United States, Saudi Arabia and the Russian Federation. Saudi Arabia is commonly described as the ‘swing producer.’ Figure 27 shows what this means. Low cost, flexible capacity is the key to playing this role in the market.

From 1970 to 2008, oil production in the United States declined by 4.5 Mbpd, from 11.3 to 6.8 Mbpd. Over that period, Saudi Arabia performed three large production ‘swings:’ two upward swings and one downward swing. The first swing increased production from 3.3 Mbpd in 1969 to 8.6 in 1974, a swing of 5.4 Mbpd in five years. The second swing decreased production from 10.3 Mbpd in 1981 to 3.6 in 1985 a swing of 6.7 Mbpd in four years and the third immediately increased production again from to 9.1 Mbpd by 1992, a swing of 5.2 Mbpd. From 2008 to 2015, the United States increased oil production from 6.8 to 12.7 Mbpd, a swing of 5.9 Mbpd in seven years, with 4.8 Mbpd of the increase in the four years from 2011, when annual production was 7.9 Mbpd.

Figure 27 Oil production by Saudi Arabia and the United States, 1965-2015

Sources: Author’s chart using oil production data from BP, Statistical Review of World Energy, 2016.

As well as being a top-three oil producer, the United States was also the largest oil importing country in the world until 2015. Figure 28 shows net imports of crude oil by the United States and net exports of crude oil by Saudi Arabia. The data shows that from 1965 to 1973, United States crude oil imports and Saudi crude oil exports almost exactly balanced each other. After the interruption following the Arab Oil Embargo of late 1973, the correlation resumed until 1979, when United States oil imports declined by about 3.5 Mbpd until 1983. United States production was almost constant though that period, and the decline in imports was the demand response to the price shocks, with a time lag as consumers, businesses and energy utilities made the investments necessary to switch to other fuels and to improve energy efficiency.

As Saudi Arabia’s own oil consumption was very small in the 1970s and 1980s, most of their production swings translated directly to export swings. Saudi Arabia’s annual production did not exceed the 10 Mbpd level of 1980 and 1981 again until 2003. Meanwhile, Saudi Arabia’s own oil consumption has grown significantly, to almost 2 Mbpd by 2003, and to 4 Mbpd by 2015. As a result, Saudi Arabia’s oil exports have never reached the levels of 1979 to 1982 between 9 and 10 Mbpd. The closest was 8.7 Mbpd in 2005. For most of the time between 1991 and 2015, Saudi Arabia’s oil exports have been between 7 and 8 Mbpd,

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with the exception of 2003 to 2006, when they were slightly above 8 Mbpd and 2009 when they were below 7 Mbpd. In other words, throughout the benchmark pricing global market era, Saudi Arabia has not provided anything like the enormous multi-year swings of production that it delivered in the 1970s and 1980s. That is an indication that the benchmark reference price oil market, together with the forward ‘paper’ market established in the mid- to late 1980s, has worked far more effectively than the posted price system.

Figure 28 shows that while Saudi exports remained approximately constant after 1990, United States oil imports continued to grow very significantly, from about 8 Mbpd in 1992 to almost 14 by 2005. Figure 29 shows that during that period exports from Russia and the other former Soviet Republics in the Commonwealth of Independent States (CIS)31 increased by 6 Mbpd—from 2.1 Mbpd in 1992 to 8.1 Mbpd by 2005, continuing to 9.7 Mbpd by 2010. That remarkable increase followed a collapse in exports from Russia and other CIS countries of 2.5 Mbpd, from 4.6 Mbpd in 1988 to 2.1 Mbpd in 1992. The production collapse was from 12.6 in 1988 to 7.4 Mbpd in 1994: a drop of 5.2 Mbpd. The Saudi upswing of 5.2 Mbpd, which added 3.3 Mbpd to exports (from 4.6 to 7.9 Mbpd) was able to more than offset the post-Soviet production and export collapse. The 6 Mbpd expansion of production from Russia and other CIS countries from 1992 to 2005 exactly balanced the increase in United States oil imports over that period, while Saudi exports remained approximately constant.

Figure 28 Oil exports by Saudi Arabia and oil imports by the United States, 1965-2015

Sources: Author’s chart using oil production data from BP, Statistical Review of World Energy, 2016. Note: production swings within the year do not appear in the annual data on which the chart is based.

After 2005, the growth of oil exports from Russia and other CIS countries slowed, but still increased by 2 Mbpd to 2015. This increase in exports occurred despite imports by the United States declining by 7.5 Mbpd after 2007. As the United States’ oil imports have declined, China’s oil imports have grown very strongly. In 2015,the volume of China’s oil imports overtook that of the United States and elevated China to the world’s largest oil importer.

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Figure 29 Oil exports by Saudi Arabia and the CIS and oil imports by the United States, 1965-2015

Sources: Author’s chart using oil production data from BP, Statistical Review of World Energy, 2016.

Figure 30 Oil exports by Saudi Arabia and imports to the United States, China and India, 1965-2015

Sources: Author’s chart using oil production data from BP, Statistical Review of World Energy, 2016.

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China’s oil imports almost equal Saudi Arabia’s exports, as shown in Figure 30. India’s imports now exceed 3 Mbpd, but the growth trajectory of India’s oil imports remains much less steep compared with that of China.

Although Saudi Arabia has not been called on since 1990 to provide the kind of enormous multi-year production swings that it delivered in the 1970s and 1980s, it is still commonly considered to have a large degree of market influence. This view of Saudi Arabia is supported by it being one of the three largest oil producers in the world, as the world’s lowest cost oil producer, as holder of most of the world’s flexible spare capacity, and the leading member of OPEC. The next section considers the extent of producer concentration in the crude oil market and the capacity of Saudi Arabia and OPEC to influence the market.

2.2.4. OPEC concentration and capacity to influence the market

OPEC's objective, as publicly stated on its website, is:

‘to co-ordinate and unify petroleum policies among Member Countries, in order to secure fair and stable prices for petroleum producers; an efficient, economic and regular supply of petroleum to consuming nations; and a fair return on capital to those investing in the industry.’32

The existence of OPEC increases the market power of its members by creating a concentration of oil supply. The standard economic measure for market concentration is the Hirschmann-Herfindahl Index (HHI), which is calculated as the sum of the squares of the market shares. A market with one supplier (a monopoly) will have an HHI of one. A market with two suppliers with equal market shares will have an HHI of 0.5, and so on. A market with an HHI of 0.25 is considered an oligopoly. A market with an HHI of 0.15 or below is considered to be unconcentrated or ‘competitive.’ Figure 31, charts the HHI for world oil production for the past half century.33

Figure 31 Changes in concentration and OPEC’s degree of influence, 1965-2015

Sources: Author’s calculations using country oil production data from BP, Statistical Review of World Energy, 2016. Note that the values are HHI concentration indices, not simple proportions.

The line labeled ‘producer countries’ is calculated as if each country was an independent competing entity. This shows that the market for the production of oil is not naturally concentrated within national borders. However, when OPEC member countries are taken as a single entity, the concentration increases substantially. The concentration of OPEC production peaked in 1973 at 0.34: well above the 0.25 level

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indicative of a concentrated market. Since 1980, the market concentration index for world oil production has varied between 0.15 and 0.25, which is considered ‘moderately concentrated.’ The underlying concentration of oil production at the nation state level declined throughout the 1980s and 1990s—accompanied by stable prices at low levels—and has ticked up again slightly since 2010. But the intrinsic concentration of oil production at the level of nation states (i.e. without treating OPEC as a single entity in the calculation of market concentration) remains low.

Focusing on the concentration of oil exports, rather than production, changes the picture markedly. This view of the data reveals just how powerful OPEC’s position in the oil export market was prior to 1981. The HHI for oil exports peaked at 0.73 in 1974. This is equivalent to the concentration in a market with a duopoly where the largest player has a share well over 80 per cent.

Since 1980, the concentration of the global oil export market has fluctuated between 0.3 and 0.5 and is at present 0.4. This is still a very dominant position, and meets all the definitions of a very concentrated market. However, OPEC is a somewhat large and rather unwieldy organisation, and only marginally stable as a cartel.34 Saudi Arabia is clearly the natural leader within OPEC as a result of its size and especially its flexible spare capacity. As is typically the case with any large cartel structure, OPEC members have, over the years, tended to produce in excess of their agreed production quotas. In the 1980s, OPEC was not able to sustain prices following the entry of new production in the North Sea and elsewhere, and production increases by the Soviet Union. In recent years, under market share pressure from United States shale oil as a new entrant, OPEC has struggled to reach agreements on production quotas.

The import side of the oil market remains very unconcentrated. Between 1965 and 2005, the index of concentration for imports was between 0.08 and 0.1, and close to 0.1 for most of that time. Since 2005, the concentration of imports has declined further and is currently 0.06. That is less than the underlying concentration of production by country (currently 0.07) and the underlying concentration of exports by country (currently 0.09). The fall in import concentration reflects the eastward shift of oil demand (but not of oil production) associated with the rise of China, as well as India and emerging Asia more generally. Notwithstanding the 2015-16 crash in the oil price level, and present anxieties about slower global economic growth and the challenges of structural transition for the Chinese economy, the trend observed since 2005 of increasing competition among oil-short countries for imports is most likely to continue with increasing strength. This conclusion is based on several observations. The combination of very large populations and steadily rising income levels mean that demand for oil in Asia is expected to continue to increase. Efforts to transfer the United States shale gas experience to China and elsewhere have been disappointing, and there are currently no indications that countries in Asia will be able to produce shale oil at rates sufficient to significantly reduce the region’s need for oil imports.

On the supply side, the market concentration of oil exports as a result of the OPEC grouping is not expected to return to pre-1980 levels, because there is now more supply from many non-OPEC sources. On the other hand, OPEC’s dominance is not likely to decline materially in the foreseeable future. Since the formation of OPEC, the concentration index for exports has never been as low as 0.3. The index briefly touched 0.33 in 1985 and 0.32 in 2002, prior to China’s ‘golden decade’ of very rapid economic growth. A concentrated market in which OPEC has a large share of exports is not by itself sufficient to give OPEC market power. There have been periods in which OPEC has been in a position to influence prices, but OPEC has not been in a position to control the oil market since the early 1980s. During that period OPEC has been neither all-powerful, nor irrelevant.

Throughout the United States shale oil boom, the index of export market concentration was very stable between 0.38 and 0.41. It must be remembered that United States production growth has only reduced United States imports, not diversified world exports. As the United States oil import requirement decreases, the world import market available to exporters becomes somewhat more concentrated. The United States remains the world’s second-largest oil importer (6.7 Mbpd in 2015) behind China, which took the number one position in 2015 (7.7 Mbpd) and ahead of Japan (4.2) and India (3.3) in a world where just over 50 Mbpd of oil is imported.

OPEC export dominance was a Euro-Atlantic (and Japanese) problem in the 1970s. This is reflected in the parties to the International Energy Program (IEP) Treaty and membership of the IEA. OPEC was not in a dominant position in the 1980s and 1990s, due to the post-1970s diversification of supply. Since 2005, OPEC export dominance has increasingly become a source of concern for rapidly developing Asia. However, as China’s oil import demands accelerated and throughout the price surge, the degree of concentration in the crude oil export market remained at similar levels to the 1980s and 1990s, as the chart

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of the concentration index shows. This is consistent with the observation that the market managed to balance supply and demand and functioned well between 2004 and 2014, without any 1970s-style crises.

The oil export market does meet the standard definition of market concentration. Given this, and the fact that spare capacity is even more highly concentrated than exports, what does the behavioural data show, and what conclusions can be drawn about the role of Saudi Arabia as swing producer and its ability to balance the market?

2.2.5. OPEC quotas and oil production

Since the early 1980s, OPEC members have met from time to time to discuss and agree on production quotas. The stepped blue line in Figure 32 shows the production quotas announced by OPEC. The stepped brown line near the bottom of the chart shows the Saudi quota, and the lighter stepped blue line shows the subtotal of the OPEC quota not including Saudi Arabia. The data are as published by OPEC. The smooth lines show production data as published by BP for all OPEC countries and for Saudi Arabia.

Figure 32 OPEC and Saudi Arabia announced production quotas, 1982-2015

Source: Author’s chart using data from OPEC, Annual Statistical Bulletin, 2016 and BP, Statistical Review of World Energy, 2016. Saudi production capacity is inferred from the BP production data and the United States EIA estimate of Saudi spare capacity. Note: this chart does not include unaccounted for production, thought to originate largely from OPEC countries. Production includes natural gas liquids, which are not subject to OPEC quotas.

The data shows that production by Saudi Arabia, and more notably by the other OPEC members, has always exceeded the production quotas except for a brief period in the 1980s. This is consistent with the economic theory that an organisation with as many members as OPEC is testing the upper limits of a stable producer cartel. Hence, while OPEC’s market share satisfies the definition of market concentration, the large number of members within the organisation and the economic dynamics drive production in excess of announced production quotas. At the margin, the revenue payoff for an individual country to produce more than its quota is greater than the revenue payoff from the higher prices that would arise if that country adhered to its quota.

The 2015 production level globally is about 95 Mbpd. Of this, about 38 Mbpd is from OPEC. OPEC’s current production quota has officially been 30 Mbpd since 1st January 2012. Since August 1986, OPEC production has consistently exceeded the announced quota. The margin by which current OPEC

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production exceeds the official OPEC quota is greater than for most of the period since the 1980s. OPEC production in 2012 was 37.5 Mbpd, 36.6 Mbpd in 2013, 36.7 Mbpd in 2014, and 38.2 Mbpd in 2015.35

Figure 32 also shows Saudi Arabia’s OPEC quota since 1982; the data shows that presently there is effectively no quota. The EIA’s published estimate of Saudi spare capacity on a monthly basis since 2003 is also shown; comparing this with the BP data on Saudi production allows Saudi Arabia’s approximate total production capacity to be estimated as approximately 13.6 Mbpd. According to the EIA, spare oil production capacity in Saudi Arabia is between 1.0 and 1.5 Mbpd. Saudi spare capacity was as high as 4.44 Mbpd in October 2009 during the global financial crisis, and less than 0.428 Mbpd in late 2008. That indicates a production swing range of about 4 Mbpd, or ±2 Mbpd either side of a balanced market.

Figure 33 shows OPEC and non-OPEC supply disruptions from early 2011 to mid-2016. The reduction in Saudi Arabia’s spare capacity—accounted for by increased production by Saudi—over the same period approximately equals those supply disruptions. In other words, supply disruptions around the world were offset by Saudi Arabia using its spare capacity to increase production.

Figure 33 OPEC and non-OPEC supply disruptions

Source: Published by United States Energy Information Administration | Updated monthly, Last Updated 9 August 2016 EIA (2016), ‘Unplanned supply disruptions tighten world oil markets and push prices higher’ www.eia.gov/finance/markets/supply-opec.cfm accessed 5 October 2016

The history of OPEC members exceeding production quotas tends to support the view, consistent with economic theory, that cartels such as OPEC are unstable. 36 Nevertheless, OPEC has survived continuously since 1960, although for significant periods, notably in the 1980s and 1990s, OPEC has not been able to sustain prices and has been forced to defend market share. That is again the situation that faced OPEC as the oil price collapsed in late 2014. The inability to defend price at times does not render the organisation redundant, given that defense of market share is also a priority for cartels.

2.2.6. The management of spare capacity

Price signals from the oil forward markets, and derivatives markets influence injections and withdrawals from commercial storage, and the management of spare production capacity.

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Figure 34 Changes in Saudi Arabia crude oil production and WTI crude oil prices

Source: Published by United States Energy Information Administration, Thompson Reuters Updated monthly, Last Updated 9 August 2016; EIA (2016), ‘Changes in Saudi Arabia crude oil production can affect oil prices’ www.eia.gov/finance/markets/supply-opec.cfm accessed 5 October 2016

Figure 35 OPEC spare production capacity and WTI crude oil prices

Source: Published by United States Energy Information Administration, Thompson Reuters Updated monthly, Last Updated 9 August 2016; EIA (2016), ‘During 2003-2008, OPEC’s spare production levels were low, limiting its ability to respond to demand and price increases’ www.eia.gov/finance/markets/supply-opec.cfm accessed 5 October 2016

Likewise, storage behaviour and inventory levels, production (relative to demand) and the level of spare capacity influence forward markets, futures markets and derivatives markets, and the spot price for prompt (near-term) delivery of crude oil. The responsiveness of Saudi spare capacity to changes in oil prices can be seen in the quarterly data of year-on-year changes in Saudi production compared with year-on-year changes in the WTI oil price, as shown in Figure 34.

The maximum year-on-year increase in quarterly production level since 2001 was 1.5 Mbpd, which occurred in 2003, and the largest year-on-year decrease in quarterly production was just over 1 Mbpd during the GFC in 2009. During the 2008 price surge, Saudi quarterly production was only able to increase by just under 1 Mbpd on a year-on-year basis. In the chart, the maximum difference between any two data points four quarters apart is about 2 Mbpd, which supports the view that Saudi Arabia normally maintains about that level of spare capacity through the balancing cycles. It is notable that a swing capacity of

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2 Mbpd is far smaller than the 5 to 7 Mbpd multi-year production swings that Saudi Arabia performed in the 1970s and 1980s, as shown in Figure 27 on page 40.

Figure 35 shows that OPEC’s total spare capacity was close to being exhausted at the height of the price surge in 2008, when there was only 1 Mbpd on average spare by the third quarter. More than 4 Mbpd of capacity became spare again during the GFC.

Interestingly, the level of OPEC spare capacity was even lower in the second half of 2004, before the price surge started. By mid-2016, the level of spare capacity is again comparable to the level in the 2008 price peak, as trade flows shift in response to reduced United States crude oil imports, and Saudi Arabia and other OPEC producers seek to defend their export market share.

2.2.7. Economics, the value chain, costs and other considerations

As noted in section 2.1.8, the upstream part of the value chain is the most capital-intensive part of the oil industry. It is exploration and production that drives the economics of oil products. Oil price formation cannot be viewed simply through the lens of the marginal cost of production: it is shorter-run dynamics that influence prices, because the cost structure is capital-intensive and the marginal cost of production of existing assets is very low. The cost curve of currently producing fields is also not necessarily a reliable guide to near-term prices; in market conditions where producers—particularly oil exporting countries—have a degree of pricing power, the oil price needed to meet government commitments and balance the national budget (known as the ‘fiscal break-even price’) tends to be cited by analysts as a key factor in oil price formation.37

Yet when supply and demand conditions are loose, prices can fall well below the level needed to justify new investments. Prices can even fall below the level needed for marginal producers to earn a return on earlier investments and governments in producing countries to break-even on their fiscal budgets. The fiscal break-even data shows that government budgets for oil exporting countries rise and fall, with a lag, in response to oil prices (IMF, 2016b, Table 6). In an echo of the 1980s and 1990s, market prices since 2014 have demonstrated that budget commitments of oil-exporting governments do not provide a guaranteed floor under oil prices, because market conditions can occur in which OPEC is not able to exert upward pressure on prices.

Bearing these caveats in mind, it is informative to review estimates of the long-run cost of oil supply, and how those estimates have been revised over time, in particular before and after the shale oil revolution in the United States. Figure 36 shows the estimate of the long-term oil-supply cost curve, as compiled by the IEA in 2008. Note that ‘oil shales’ in the chart are not the same as ‘shale oil.’ The former involve the use of heat such as steam retort methods to extract oil. In contrast, ‘shale oil’ or ‘light tight oil’ involves horizontal drilling and hydro-fracking the source rock to stimulate the oil to flow out of the wells.

Figure 36 Long-term oil-supply cost curve

Source: IEA (2008a), Figure 9.10, p.219. Note (from the original source): The curve shows the availability of oil resources as a function of the estimated production cost.

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Cost associated with CO2 emissions is not included. There is also a significant uncertainty on oil shales production cost as the technology is not yet commercial. MENA is the Middle East and North Africa. The shading and overlapping of the gas-to-liquids and coal-to-liquids segments indicates the range of uncertainty surrounding the size of these resources, with 2.4 trillion shown as a best estimate of the likely total potential for the two combined.

As recently as 2008, shale oil was considered hopelessly uneconomic and was not even included on the long-term supply chart. Marginal sources of supply, beyond conventional oil outside the Middle East and North Africa (MENA) was estimated to have production costs of between $55 and $110 per barrel, with 1.1 of 9 trillion barrels of geological oil resources having been already produced, and 7.9 trillion barrels remaining in the ground.

2.2.8. Both supply and demand are inelastic in the short run

History indicates that when the market is out of balance on the order of one or two per cent of global supply or demand, very large price movements tend to be needed to rebalance it. This reflects the characteristics of the oil market, which in economic terms is very inelastic in both supply and demand in the short term. Because the oil price is very sensitive to an imbalance between supply and demand a large price movement is needed to prompt a relatively small change in demand and supply to rebalance the market.

Oil demand is inelastic in the short-run for a number of reasons. Most transport is essential for the daily movement of people and goods: despite high prices in a tight market, substitutes for transport tend to be unavailable, inconvenient or expensive in the short-term. Estimates of short-run oil price elasticity in the

literature tend to be around ‑ 0.2: i.e., for every one per cent increase in prices, demand decreases by 0.2 per cent. In the longer term, the market responds to high prices in a number of ways, including more efficient vehicles and location decisions that reduce the need for transport. Consequently, estimates of long-run demand elasticity are considerably higher, approaching unity.

In a loose market, very low prices are needed to encourage more oil use. Discretionary travel (such as holidays and other leisure travel) represent a relatively a small share of transport demand, and the cost of oil represents only a part of the expenditure required for discretionary travel. Price expectations, rather than current price levels, are the key to decisions about the efficiency of new vehicle purchases, and with new vehicles representing on the order of one-tenth of the vehicle stock, there is a lag before price falls will feed through to increased consumption due to the purchase of larger vehicles.

In addition to the general price elasticity effect, the presence of substantial taxes tend to ‘dampen’ the effect of changes in the upstream price of crude oil. A doubling (or halving) of the oil price translates into much smaller percentage changes in retail petrol and diesel prices in most countries. For this reason, and others, it is important to distinguish between the price elasticity of crude oil demand, and the price elasticity of demand for refined products. Studies on the price elasticity of gasoline (petrol) demand seem to be more numerous in the literature than studies on the elasticity of diesel demand.

Another important consideration is what Levin et al (2016) term the ‘response horizon’ of estimates of price elasticity: the difference between short-run and long-run elasticity. As ACIL Allen (2014) state:

There are many widely-cited estimates of short- and long-term price elasticity of demand for automotive fuel for various OECD countries. Invariably, estimated long-term price elasticities have been substantially higher (ignoring the negative sign) than short-term price elasticities, consistent with expanding opportunities to adjust fuel-use that become available as time elapses.

Estimates have been made by various authors in many countries of the elasticity of oil demand in the short-

and long-run. Estimates of short-run elasticity of gasoline or petrol demand range from ‑ 0.2 to ‑ 0.47. It is important to note that these are not crude oil price elasticity estimates, but are based on retail prices, including taxes. Most estimates for the OECD as a whole and for most OECD countries are in the range

‑ 0.2 to ‑ 0.3. In other words, a one per cent increase in petrol prices would result in a decrease in demand of about 0.25 per cent in the short-run. Estimates of the long-run elasticity of petrol demand range from

‑ 0.7 to ‑ 1.0, with some authors estimating ‑ 1.2 and ‑ 1.35 for the OECD. (Graham and Glaister, 2002). Petrol tax multipliers are lowest in the United States and Canada and highest in the UK and the EU, with Australia and Japan in between. As a result, changes in the crude oil price have a greater effect on demand for petrol in the United States than in the EU.

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2.2.9. Demand may be somewhat more elastic in the short run than has been estimated

ACIL Allen (2014, p. 32-33) reviews the literature on the price elasticity of petroleum product demand and critiques by economists of other economists’ estimates. In a recent study, Levin et al (2016) applied econometric analysis techniques to city-level daily gasoline purchase data from VISA cards for 243 metropolitan areas throughout the United States spanning 47 months from February 1st 2006 to December 31st 2009. The period is notable for a steep surge in prices, followed by a steep collapse in prices. Underlying crude oil prices changed over a very large range during that period. Analysis using daily prices

and purchase data at the city level suggested that demand is more price-elastic (‑ 0.323) than was the case when the daily city data set was aggregated:

Estimating the model using our data aggregated to a national time-series of monthly total expenditures and average prices results in elasticities that are indistinguishable from zero, suggesting that studies using aggregated data may substantially underestimate consumers’ price responsiveness.38

The results lead Levin et al (2016, p.40-41) to conclude:

More accurate elasticity estimates can also substantially impact the inferences one draws when evaluating the macroeconomic costs of gasoline and oil market disruptions and the benefits of policy responses like maintaining a Strategic Petroleum Reserve (SPR) that are intended to reduce these costs. If gasoline demand were significantly more elastic than previously thought, prices will likely increase substantially less than would otherwise be predicted in response to a oil supply disruption, and the quantity consumers will purchase at these prices will be substantially smaller. As a result, the overall macroeconomic displacement effect is likely to be much smaller that would have previously been predicted. In addition, when consumers have more elastic demand, the release of a certain volume of fuel from the SPR during a market disruption will not be as effective as a policy lever aimed at reducing price levels. Our elasticity results strengthen any argument in favor of eliminating or reducing the size of the SPR or mechanisms setting price for greenhouse gas emissions by demonstrating a significantly larger price-responsiveness of gasoline demand.

2.2.10. Supply may becoming more price-elastic due to shale oil

Just as demand is inelastic in the short-run, so is supply, both in a loose market and in a tight market. As with demand, there are underlying reasons why supply is not particularly elastic with price, particularly in the short- to medium-run. Many oil fields can be damaged geologically by large swings in output and most oil production is characterised by high up-front capital costs and low operating costs. At the level of wells and fields, producers therefore have technical reasons and strong financial incentives to maintain a steady output that utilises the available production capacity. Looked at the other way, there are substantial opportunity costs to underutilized or ‘spare’ capacity. This means that in a loose market, where global production needs to be reduced to rebalance the market, very low prices are required to drive production out of the market.

In practice, the ‘fine balancing’ of supply and demand on a daily, weekly and monthly basis is managed by a combination of short-term storage and production flexibility, particularly by Saudi Arabia. In a tight market, high prices need to be sustained for long enough to provide the inventive for new investment; investors need to be confident of recovering the high up-front capital costs at their required risk-adjusted rate of return. The distinction between balancing oil supply and demand in the short-term and in the long-term is significant.

On the supply side, new investment (in a tight market) cannot, by definition, be achieved in the short run. Similarly, for technical and financial reasons, most oil fields cannot simply be shut-in and restarted on call. Therefore, on the supply side in the short-run, balance can only be achieved by storage (in a loose market) and withdrawals (in a tight market), as well as by varying production from flexible fields. The ability to increase production to balance a tight market requires spare capacity to be maintained in flexible fields. Conversely, the ability to decrease production to balance a loose market in the short-run requires the willingness to idle some capacity in flexible fields (thereby forfeiting sales volume).

Storage and withdrawals, together with flexile production, cannot rebalance the market indefinitely. If a market continues to tighten, rebalancing from the supply side can only be achieved in the long run by new investment. And if a market continues to loosen, balance from the supply side can only be achieved in the long run by shutting in production.

The literature on estimates of oil price supply elasticity is less extensive than the literature on demand elasticity. Discussion about the short-run price elasticity of oil supply has, since the 1970s, been mainly

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about the behaviour of OPEC. Beyond the ‘call on OPEC’ and OPEC’s role balancing the global crude oil market in the short-term, long-run supply growth has historically turned on the price expectations of the oil majors and the NOCs. This situation has changed with the advent of the ‘unconventional oil’ or shale oil or ‘light tight oil’ revolution in the United States since the late 2000s. Section 2.2.14 and section 3.5.8 discuss this in further detail.

2.2.11. Supply-demand fundamentals and the volatile dynamics of oil price-formation

Figure 37 shows a stylised supply curve, ‘S’ on price-quantity (P-Q) axes. This is conceptually similar to Figure 36, but instead of the long-term resource supply curve, Figure 37 represents a snapshot of production at a moment in time. A stylised demand curve ‘D’ is superimposed on the supply curve. Overlaid on the diagram are ‘Porter’s Five Forces’ of the threat of new entry increasing supply, the threat of substitution reducing demand, supplier power pushing up costs and buyer power pushing down prices, with competitive rivalry resolving the market forces (Porter, 2008).

In the case of the oil market, buyer power has at times been very limited, notably when the supply-demand balance in markets became tight as in the 1970s and between 2004 and 2014. Following the price shocks of the 1970s, supply was indeed increased by new entrants, such as North Sea producers and others responding to the incentive of high prices. Likewise the threat of substitution was realised as demand was reduced by consumers switching fuels from oil to coal, natural gas and nuclear power. During the more recent run-up in oil prices, supplier power pushed up costs for all of the hard and soft inputs to oil exploration and production such as steel and engineering services. When the market loosened, buyer power then pushed down prices, as producers sought to defend market share.

Figure 37 Porter’s Five Forces super-imposed on a Marshallian cross

Source: Author’s chart

It is important to note that Figure 37 is a static representation of what has become a very dynamic market with high price volatility. Figure 38 reproduces a chart from Kilian (2014), showing clearly how oil price volatility changed at the end of 1973. The events of that year were a watershed, marking a change in oil pricing regimes and an important boundary between eras in the history of the industry, as summarised in Table 1.

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Figure 38 Percent change in the real price of oil, Feb 1948 – Dec 1973 and Feb 1974 – May 2013

Source: reproduced from Lutz Kilian (2014) ‘Oil Price Shocks: Causes and Consequences,’ Annual Review of Resource Economics, p.136, available online at resource.annualreviews.org, doi: 10.1146/annurev-resource-083013-114701 Note: RAC denotes the United States Refiners’ Acquisition Cost as reported by the United States Energy Information Administration, and WTI denotes West Texas Intermediate crude oil.

Post-1973, price volatility (whether on a daily, weekly or monthly basis) reflects the market working continually to restore imbalances. Comparing the left and right panels of Figure 38, it is notable that the price changes from 1948-1973 were dominated by increases after long periods of stability, while price decreases were rare, whereas the price changes since 1973 include downward as well as upward price changes that have been much larger in magnitude than the price changes before 1974.

The pressure build-up of the 1970s led to a break point, eventually followed by rebalancing. This follows the model of the ‘The energy evolution cycle’ introduced in Figure 2 on page 4. The ‘energy evolution cycle’ helps explain the periodic large price adjustments described in the preceding paragraph.

Figure 39 shows the ‘energy evolution cycle’ from Figure 2 mapped on to the supply and demand curves. In the first part of the cycle, prices are relatively low. As incomes rise, demand grows in response along the supply curve, S1, as the demand curve moves to the right from D1 to D2. The demand curve is steep, reflecting the low short-run elasticity of demand. However, there is sufficient capacity available at low cost and in time to meet incremental demand.

As dependency increases and demand continues to grow, pressure builds up. As shown earlier in Figure 2, the pressure is felt from a combination of business, policy, social, geopolitical and environmental forces. Eventually the system reaches a break point, which is followed by a rebalancing of supply and demand. At its most severe, rebalancing involves a leftward shift of the demand curve, as occurred in the 1970s. Eventually there is a gradual recovery in demand together with falling prices as the cycle begins again characterized by a new supply curve that has by that time stretched to the right in response to the earlier high prices. In the case of conditions the lead to a price collapse, the supply curve may be compressed downward, as has been observed since 2014.

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Figure 39 The dynamics of price formation within volatile commodity markets

Source: left hand side: Author’s chart; right-hand side: adapted by author from Peter Tertzakian, 2007, A Thousand Barrels a Second: The Coming Oil Break Point and the Challenges Facing an Energy Dependent World, McGraw-Hill, Figure 1.1

The anti-clockwise circular process shown in Figure 39 is the most severe form of the energy evolution cycle, in which the level of demand declines in response to a very large price increase. If prices are artificially low, then growth and dependency is greater than would otherwise be the case, the pressure buildup is greater, and the break point and rebalancing is more severe. That is exactly what happened in the 1970s, particularly in the United States. Section 3.3.1 below discusses in further detail the range of demand- and supply-side actions by which the market was rebalanced at that time.

The next section describes the insights from reviewing the relationship between oil prices and the annual quantities consumed throughout periods of price stability and periods of large price changes.

2.2.12. Oil market experience of how dynamic economic forces can play out

In the 1970s, fixed nominal prices failed to reflect the consequences of strong demand growth. A looming supply imbalance, US dollar inflation and consequent erosion of oil exporters’ revenues led to a very severe break-point followed by a painful rebalancing with large-scale demand destruction in the 1980s that was painful for consumers and later for producers. The earlier failure of pricing policy was then compounded by emergency rationing in the United States, which also failed.

From Figure 1 in the ‘Overview and introduction,’ the contrast between volumes and prices is clear. Figure 40 is based on exactly the same data as Figure 1, but plots each annual average price against the corresponding annual volume to produce a price-quantity chart. This shows the evolution of world crude oil consumption versus international price levels over the past half century. Prices have been adjusted for inflation, and are presented in 2015 dollars. The chart clearly shows the two major discontinuities: the oil shocks in the 1970s, and China’s demand surge of the 2000s.

At the break point, there is usually a catalyst or an external trigger—which should not be confused with the cause—and a price shock. This is recognised in the official history of the IEA (Scott, 1995b, p.25, emphasis in the original):

The vulnerability of the industrial countries to serious oil supply disruptions and to price shocks occurring largely outside of their control was not a sudden development, although the awareness of the associated risk did appear suddenly to many energy policy makers only late in 1973 when the crisis began. The combination of situations [that] created the crisis evolved over a number of years before the crisis occurred.

In the 1970s the catalyst for the break point, which led to a price jump, was a regional conflict in the Middle East and an OPEC embargo disrupting supplies. A second regional conflict triggered a second price jump in 1979, and the major rebalancing of the 1980s and 1990s followed.

After the pressure buildup of the 2000s the catalyst for a price collapse came in the form of a major financial crisis, but the price soon rebounded, and in response to sustained high prices, a new source of supply in the form of United States light tight oil emerged, which triggered a second price collapse and the rebalancing phase.

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The steepness of the line joining the price-quantity (P-Q) co-ordinate for 1973, with the P-Q coordinate for 1974 gives a very graphic sense of the extreme inelasticity of short-run demand: the line is almost vertical. A curved line joining 1973 to 1979 also gives a rough sense of the inelasticity of supply in the short-run. The size of the world oil industry had doubled in the thirteen years from 1965 to 1978. In the 37 years since 1978, the industry increased in production volume by a little more than 50 per cent: about half the volume growth in almost three times as many years.

The curved line joining the coordinates for 1998, 2009 and 2011 show the extent to which the supply curve was shifted to the right in the 20 to 30 years after 1978, following the investments in new oil supply during the 1970s and 1980s. The steepness of that curve is also a reminder that short-run supply remains inelastic, which becomes apparent when demand growth is high and dependency is driven by a period of low prices.

The supply curve should not be thought of as representing only the underlying economic costs of production, as it also embodies the prevailing fiscal terms of the producing countries. The negotiation of fiscal terms between host governments and international oil companies and investors is a special case of supplier power (in the form of host governments managing their national resource endowment) and buyer power in the form of prospective investors looking to secure equity oil on attractive commercial terms.

In the 1970s, the global oil supply simply could not be doubled in a decade or less, which is what household and business oil consumers collectively were implicitly demanding, at the prices they were being offered. Even with all the will and technical expertise in the world, doubling oil supply in a decade was probably impossible for the industry at any price. It was certainly impossible at low prices. And low prices (actually: low posted prices despite increasing US dollar inflation) combined with runaway demand proved incompatible with the good will of producers. As we now know, growing the oil supply curve from 55 to 60 Mbpd to over 90 Mbpd, at prices ultimately acceptable to all stakeholders (consumers, producers, and governments in oil exporting and oil importing countries) as discovered by the market as it evolved, would take the industry about four decades, not one.

From Figure 40 it is evident that the price cycle that peaked in 2008 and 2011 was less severe than the oil price shocks of 1973-74 and 1979-80. The P-Q trajectory did not loop back on itself as it did in the 1970s.

Figure 40 Evolution of world crude oil consumption and international prices, 1965-2015

Sources: Author’s calculations using data from BP, Statistical Review of World Energy, 2016. Prices are in 2015 dollars.

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Figure 41 Indices for the capital costs of upstream oil production and oil prices

Source: www.ihs.com/info/cera/ihsindexes/ and www.eia.gov/dnav/pet/pet_pri_spt_s1_d.htm

Oil demand fell only very slightly from 2008 to 2009, whereas the collapse in demand from 1979 to 1982 was much larger in both absolute and percentage terms. And the production growth through the cycle from 1998 to 2015 was far larger than from 1973 to 1986, even though the price surge was only moderately larger in inflation-adjusted dollars than the 1970s price shocks. Those observations all confirm that allowing the market to work proved to be an effective policy.

Although the P-Q trajectory did not loop back on itself in the 2008 and 2011 price surges, the price-cost relationship did loop back on itself. This is apparent in Figure 41, which shows the oil industry price and cost cycle, or the dynamic inter-relationship between costs and prices. The data is the same as the data in Figure 16, but with prices plotted against costs, instead of both plotted against time.

The pattern revealed is as follows:

prices escalated four-fold, followed by a slightly more than twofold cost escalation

the curve then ‘tumbled forward’ over itself (akin to a breaking wave), as prices rapidly collapsed from the peak in 2008 to only 50 per cent above the year 2000 index base, while costs remained ‘sticky’ at more than two times their 2000 level

the curve then shot up again (tracking almost exactly over the same path as in the lead-up to the 2008 peak), reaching a peak in the first quarter of 2012, before slowly ‘tumbling forward’ again, and finally collapsing almost back to the level of the real price index in the 2000 base year by the first quarter of 2016, but at more than 50 per cent above the year 2000 base year cost level.

The data is consistent with an industry in which demand and supply are inelastic in the short-run, in which costs are sticky, and whose cost structure has increased to deliver greater production, despite recent cost compression following a phase of rapid cost escalation. The data and analysis above prompts the question: What about the shale oil revolution?

2.2.13. The United States light tight oil revolution

In 2013, the IEA published an update of the 2008 oil supply cost curve, as shown in Figure 42.

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Figure 42 Supply costs of liquid fuels

Source: IEA (2013a), Figure 13.17, p.454, reproduced from IEA (2013b)

Compared with the 2008 outlook, the 2013 outlook shows slightly less available supply in MENA at about the same cost level, and slightly more conventional oil outside of MENA. The lower cost range of the 2013 outlook for new supply is $10 per barrel in 2012 dollars: a lower real cost than the $10 per barrel in 2008 dollars in the 2008 outlook. However the upper range of costs for new conventional oil outside MENA in the 2013 outlook is substantially higher: $70 (in 2012 dollars), compared with $39 per barrel in 2008 dollars, equivalent to about $41.50 in 2012 dollars.

The 2013 outlook includes eight trillion barrels of oil reserves compared with nine trillion barrels in the 2008 outlook, while only about 160 billion barrels were consumed between 2008 and 2013. The IEA’s cost estimate for extra heavy oil and bitumen had increased between 2008 and 2013 to a range of between $50 and $90 per barrel, up from $37 to $69 per barrel in 2012 dollars in 2008 ($35 to $65 in 2008 dollars).

Figure 43 World supply cost curves for 2013 and 2035 in the IEA New Policies Scenario

Source: IEA (2013), Figure 13.18, p.456. Note (from the original source): The vertical green line indicates the amount of production required between 2013 and 2035 in the

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New Policies Scenario (NPS).

Figure 44 Non-OPEC supply cost curves for 2015 and 2040 in the IEA New Policies Scenario

Source: IEA (2015), Figure 1.4, p.48. Note (from the original source): EHOB = extra-heavy oil and bitumen. The vertical green line indicates the amount of production required between 2015 and 2040 in the New Policies Scenario.

Light tight oil, which did not appear on the supply curve in 2008, is included on the 2013 curve at a cost range of between $50 and $100 per barrel. The lower half of that cost range—$70 to $90 per barrel—overlaps with the upper portion of the cost range for conventional oil outside MENA. It is that overlap, and the fact that oil prices were between $100 and $120 per barrel from 2011 to 2014, which allowed light tight oil to displace conventional oil. The lowest cost shale oil resources were infra-marginal during the recent high oil price period, and are now marginal. The high cost shale oil resources were marginal during the recent high oil price period and are now uneconomic.

However, several important points should not be overlooked here:

At $50 per barrel, the lowest cost light tight oil resources are double the cost of the highest cost oil resources in MENA at $25 per barrel.

Transport costs and other adjustments to benchmark prices mean that light tight oil producers receive considerably less than the prevailing benchmark price at the well-head, in some cases $10 to $20 less.

The ‘slice’ of light tight oil resource in the IEA cost curve is not large, it is much smaller than the remaining resource of conventional oil outside MENA, and slightly smaller than the remaining resource of conventional oil available from enhanced oil recovery (EOR) using carbon dioxide (CO2).

Those points provide helpful context for the United States light tight oil or ‘shale oil’ revolution, as it is currently understood. Our understanding of this technological change in the oil industry continues to evolve with experience, and as more data and information becomes available. Figure 43 shows the IEA’s estimate from 2013 of recoverable reserves presented as continuous supply cost curves for 2013 and 2035, with various sub-sets of total reserves by category.

The curves suggest that the long-run marginal cost of supply of production needed to 2035 in the IEA’s New Policies Scenario (NPS) is between $45 and $50 per barrel (in 2012 dollars). The curves suggest that the inclusion of light tight oil, extra-heavy oil and bitumen (EHOB) and kerogen resources in addition to conventional crude oil have little effect on marginal costs. (This is not to say that unconventional resources would not affect prices, through market dynamics not directly related to underlying cost economics). A similar chart published by the IEA in 2015 and shown in Figure 44 suggests a materially higher cost structure in 2015 compared with 2013: about $80 per barrel in 2040, instead of $50 by 2035 in the 2013 chart. Low inflation means that the change from 2012 to 2014 dollars is small. Consistent with the 2013 chart, light tight oil and EHOB are not expected to materially affect the marginal cost of supply until after 2040.

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The addition of light tight oil does not change the shape of the supply curve to the left of the line indicating production needed to 2040. However, the presence of light tight oil has already shown its influence on price formation in a way that is not immediately apparent through cost curve analysis by it itself.

The magnitude of the change between the 2013 and 2015 charts reveals the limits to the knowledge of even the world’s leading oil experts about the likely future costs of oil production.39 The reasons for this include the dynamic interaction between costs and prices described in section 2.2.11, combined with the rapid rate of change in the early period of shale oil as the industry learns about new combinations of existing technologies (horizontal drilling and hydro-fracking) and applies them in new conditions.

2.2.14. Shale oil and marginal supply is still a significant uncertainty

Figure 45 shows the weekly drilling rig count in the United States from 1987 to the time of writing. Most of the rigs are onshore rigs: just 20 of the 511 active rigs on 23rd September 2016 were offshore rigs in the Gulf of Mexico, of which one was targeting gas, and the other 19 were targeting oil. Of the 491 onshore rigs, 399 were targeting oil, and 91 were targeting gas, with one ‘miscellaneous.’ Figure 46 shows that 402 rigs were horizontal drilling rigs, meaning they were targeting shale beds.

Figure 45 North America oil and gas rotary rig count by target, 1987-2016

Source: Author’s chart using data from Baker Hughes (2013)

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Figure 46 North America oil and gas rotary rig count by drilling trajectory, 1991-2016

Source: Baker Hughes (2013)

Several things are clear from the data:

The collapse in the oil price has dramatically reduced the number of active horizontal drilling rigs targeting oil in North America from about 1500 to about 300

The natural gas-directed rig count has not recovered following the collapse of the Henry Hub natural gas price in the United States

Most North American rigs are drilling horizontally for light tight oil

The rig count is sensitive to the price of oil.

Production data shows a much longer lag following changes in the oil price than does rig count data. That is because wells, not rigs, produce oil (and gas). Once oil and gas wells are drilled, fracked and completed, they continue to produce until they are shut-in, even though production from shale beds declines much more rapidly than production from conventional fields. The fracking and completion of previously drilled but uncompleted (DUC) wells has sustained production in the United States despite the collapse in the number of active drilling rigs. The concentration of the remaining active drilling rigs into the most productive plays, and the most productive areas of those plays has resulted in more production per well, and hence requires fewer rigs for each unit of production. Increases in the efficiency of drilling operations means that more wells can now be drilled with fewer rigs.

2.2.15. International institutions

In addition to the companies—both national and investor-owned—which collectively comprise the oil industry, there are a number of international institutions of relevance to the oil market. They include the:

Organisation of Petroleum Exporting Countries (OPEC)

Organisation for Economic Cooperation and Development (OECD)

International Energy Agency (IEA)

Asia-Pacific Economic Cooperation forum (APEC)

International Energy Forum (IEF)

Joint Organisations Data Initiative (JODI)

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World Energy Council (WEC)

OPEC is the leading organisation on the supply side of the market and the IEA is its traditional counterpart on the demand side of the market. APEC is among other leading organisations among energy importing countries, as well as several important national institutions.40

Section 6.2 in the Appendices provides an overview description of each of the above organisations.

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Chapter 3. The History and Development of the Global Oil Market

3.1. A brief historical outline of the oil market since World War 2

Decade-by-decade the oil market since World War 2 may be summarised very briefly as follows:

The 1950s: post-war recovery and rebuilding. Baby boom. Bretton Woods fixed exchange rates and dollar-gold convertibility. American consumerism, growth of suburbs, road networks, large cars with high fuel consumption. Oil price stability. Oil-fired power generation and heating. Start of the ‘Cold War’ between the United States and the Soviet Union.

The 1960s: economic and demographic trends continue. Beginning of the OPEC era and a general rise in ‘oil nationalism.’ Economic stresses that were to reach breaking point in the 1970s had begun to appear by the mid-1960s.

The 1970s: two major ‘oil shocks’ and the formation of the IEA. Stagflation (a stagnant economy accompanied by inflation), breakdown of the Bretton Woods system, rapidly rising gold and oil prices. France embarked on a major nuclear power programme, as did Japan, which diversified away from oil to nuclear, coal and gas for electricity generation. The United States also continued to build nuclear power plants.

The 1980s: after the Three Mile Island nuclear plant emergency in 1979, no new reactors were approved until several decades later. The last decade of the Cold War. Inflation under control through a period of very high interest rates. Oil prices subsided from their 1970s highs in both nominal and real terms. OPEC considered production cuts to support prices, but concluded that it was a lost cause.41 From 1980-84 the Soviet Union produced at more than 12 Mbpd, and sustained production at more than 10 Mbpd until its collapse in 1991. A Soviet reactor meltdown at Chernobyl in Ukraine further contributed to public anxiety about nuclear power in the West.

The 1990s: heralded a ‘New World Order’ and the ‘end of history.’ China’s predicted boom did not (yet) arrive, and was dismissed by many after the Asian financial crisis of 1997. Oil prices continued a long, slow decline, along with most other energy and mineral commodities. By 1997 Russia’s oil production had collapsed to just above 6 Mbpd from more than 10 Mbpd in 1990.42 Russia defaulted on its sovereign debt in 1998, and there was concern that the collapse of Long Term Capital Management in New York might trigger a collapse of the global financial system. Real oil prices reached the bottom of the long post-1970s decline in 1998. The 1990s saw reforms to introduce competitive electricity markets in the UK, Australia and parts of the United States, the lifting of regulations preventing the use of natural gas for power generation, and significant improvement in gas-fired power efficiency.

The 2000s: the economic boom in China, with energy and commodity-intensive development of infrastructure and cities driving the largest surge in demand for oil, energy and commodities in general that the world has ever seen. Double-digit growth in China moved world markets. Supply of oil (and many other commodities) struggled to keep pace with demand growth. Steel price increases fed back into the cost of developing new oil fields and building new pipelines and tankers. The cost base more than doubled and the price of oil quadrupled relative to year 2000 levels (see Figure 16). Followed by the largest financial market crash since the Great Depression of the 1930s: the Global Financial Crisis (GFC) of 2008-09.

The 2010s: growth spurts, awkwardness and deep uncertainty. Large-scale monetary stimulus from central banks led by the United States Federal Reserve Bank. Financial markets, oil and commodity markets rebounded in 2010. In late 2014 and early 2015, the oil price collapsed from the post-GFC price rebound. Surge in the production in the United States of light tight oil using fracking of shale rocks, adding more than 5 Mbpd to United States production, thereby reducing United States oil imports and changing global trade flows.

Complementing the brief decade-by-decade descriptions above, Table 4 summarises several eras in the post-war evolution of the oil market. Major events or changes rather than calendar decades have been chosen to delineate the eras. The table looks at slowly unfolding underlying trends, rather than distinct historical events.

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Table 4 Evolution of the oil demand, supply, exports, imports and pricing since World War II

Demand centre: America Atlantic basin Transition east

Approximate period 1945-1973 1974-1999 2000-2015

Demand dominated by US, EU + Japan OECD Non-OECD

Imports dominated by Europe Europe + US Europe + US

Exports dominated by Concessionaires OPEC OPEC

Supply most influenced by US & OECD OPEC…NOCs …US shale…

Oil price set by ‘Seven Sisters’ posted prices / balanced in Texas with TRC regulation

OPEC posted prices…then benchmark pricing and futures trading, OPEC balancing

Price discovery in a mature market balanced by OPEC

Global monetary system Bretton Woods Floating USD Tensions and crisis

Source: author’s analysis. Note: Concessionaires were largely United States oil companies in Saudi Arabia, and western oil companies in the Middle East

Some important trends have become clear, particularly the dominance of demand by non-OECD Asia. The West (Europe together with the United States) remains the largest importer, but this is changing as demand shifts relentlessly eastwards. In the half-decade since 2010, the rapid emergence of infra-marginal United States shale pushed out marginal conventional oil projects in ultra-deep water, the high arctic and Brazilian pre-salt plays. The light tight oil shale fracking phenomenon happened in a world with real oil prices at all-time historical high levels, and real interest rates at all-time historical low levels. OPEC continues to dominate oil exports, nowhere more so than in the Asia Pacific region.

The changes described above have been instrumental in the changing role of oil.

3.1.1. How has oil’s role changed over time?

During the 1970s, 1980s and 1990s, nuclear power, coal and gas largely replaced oil for electricity generation. Natural gas displaced a large proportion of heating oil, including in much of industry. This has left transport as the main market for oil products and oil as the near-monopoly fuel for transport. As a result, during the half-century from 1965 to 2015, oil has gone from 49 per cent of primary energy consumption worldwide in 1973 to 33 per cent in 2015, as shown in Figure 47.

Figure 48 shows that the share of oil in primary energy consumption varies enormously between countries, but that the range has narrowed since the oil price shocks of the 1970s. Surprisingly, in Japan the oil share of primary energy is 42 per cent, despite being 100 per cent energy import-dependent and despite decades of fuel mix diversification and energy efficiency policy. While a considerable reduction compared with 77 per cent in 1973 at the time of the first oil shock, 42 per cent is still high compared with other countries. In the United States, the EU and the OECD as a whole, the oil share of primary energy consumption is 36 to 37 per cent. In Australia it is 35 per cent, slightly above the world average of 33 per cent.

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Figure 47 Oil, gas, coal and non-fossil fuel as a share of world primary energy supply, 1965-2015

Source: BP, Statistical Review of World Energy, 2016

Figure 48 Oil share of primary energy in the world, and selected major economies, 1965-2015

Source: BP, Statistical Review of World Energy, 2016. * Asia Pacific here excludes Australia, China, India, and Japan.43

For developing economies the share is much lower than the world average. In China oil has a 19 per cent share of primary energy, and in India oil has a 28 per cent share: markedly lower than the world average. It

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is remarkable that the oil share in the rest of Asia Pacific is as high as in Japan, and that although the oil share was not quite as high as Japan in the 1970s, the pattern throughout the over the past half century has been very similar to Japan.

Asia Pacific countries in the chart include (in descending order of primary energy consumption) South Korea, Indonesia, Thailand, Taiwan, Malaysia, Singapore, Pakistan, Vietnam, the Philippines, Bangladesh and Hong Kong, as well as other smaller economies. Collectively, these represent 22 per cent of primary energy consumption in Asia Pacific.

Oil import dependence is high and growing among Australia’s neighbours in the Asia Pacific region.

3.2. Change and continuity

The history of the industry’s development after World War 2 may be summarised in four phases:

Phase 1: Stability and growth with some signs of trouble—post-war and the early years of OPEC

Phase 2: Conflict and ‘stagflation’—the IEP Treaty and the formation of the IEA

Phase 3: Stability and growth in the ‘New World Order’

Phase 4: The ‘return of history,’ Chinese super-growth, financial crisis and stalled growth

3.2.1. Phase 1: Stability and growth—the early years of OPEC

OPEC was established in 1960 by Saudi Arabia, Iran, Iraq, Qatar and Venezuela. In 1967 there was an embargo by several Arab countries on oil exports to the United States and the UK and other countries associated with the Arab-Israeli Six Day War. The embargo was ineffective and short-lived, but in hindsight presaged the 1973 embargo. United States military involvement in Vietnam was a source of civil unrest and 1968 saw violence demonstrations in the United States and France. US dollar-gold convertibility began to be tested, first by France, and then by other countries.44

Nevertheless, the period from 1965-1973 saw stable oil prices accompanied by substantial and accelerating growth in oil demand. This demand growth was led by post-war America, the post-war reconstruction of Europe and the re-industrialisation of Japan throughout the latter half of the Bretton Woods era.

In the late 1960s, oil prices actually declined by between 2.7 and 5.6 per cent per annum (averaging 4.0 per cent) per annum while oil consumption grew by between 6.0 and 8.7 per cent (averaging 7.7 per cent) per annum. In 1971, the annual average oil price level jumped by more than 19 per cent over the 1970 level. World oil consumption increased by 6.0 percent, notably below the growth in 1965-70 and 1972. While barely noticeable in Figure 40, 1971 may be seen as presaging the shocks of 1973-74 and 1979-80. President Nixon closed the US dollar gold window on 15 August 1971, effectively ending the Bretton Woods era; at around the same time, the Kuwaiti oil minister is reported to have asked: “What is the point of producing more oil and selling it for an unguaranteed paper currency? Why produce the oil which is my bread and butter and strength and exchange it for a sum of money whose value will fall next year by such-and-such a percent?” (Yergin, 1991, p.595).

The 1960s saw a change in the contractual arrangements between host countries and international oil companies (IOCs). The contract form that came to be known as a Production Sharing Agreement (PSA) was first introduced by Indonesia in 1966. Over time, PSAs displaced concession agreements, which had been the normal approach around the world since at least 1901 in Persia (Bindemann, 1999).

3.2.2. Phase 2: Conflict and ‘stagflation’—the IEP Treaty and the formation of the IEA

The period from 1973-1980 saw a number of significant international events, which had a material effect on oil markets. These included: the Yom Kippur War and the Arab Oil Embargo in 1973; the formation of the International Energy Agency in 1974; the Soviet invasion of Afghanistan in 1978; and the Iranian Revolution and United States Embassy hostage crisis in 1979. The 1973 and 1979 events were accompanied by steep price increases—five-fold in real terms—constraining demand growth. This occurred in two steps. In the first step, the annual average oil price in 1974 was 217 per cent higher than in 1973, and consumption was 1.4 per cent lower. Had consumption growth continued on trend, it would have been between seven and eight per cent higher. These numbers give an indication of the short-run elasticity of oil

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demand. The initial step-change was followed by a resumption of consumption growth at the higher price levels, which remained quite stable in real terms. The growth rate was lower than previously at between 3.7 and 6.2 (averaging 5.0) per cent per annum from 1976-78.

Then in 1979, prices jumped by more than 100 per cent over the 1978 level with consumption growth reaching 1.8 per cent, and then negative for the following four years from 1980 to 1983 inclusive, even as prices fell. As the United States (and other economies, including Australia) emerged from recession in 1984, oil prices fell precipitously, halving in real terms from 1983-86, yet consumption increased slowly, averaging only 2.0 per cent in the three years to 1986.

The 1973-74 period came to be known as the ‘first oil shock.’ The 1978-80 period came to be known as the ‘second oil shock.’ This period saw the increasing assertiveness by host countries leveraging their resource ownership in negotiations. States increasingly took a high participating interest in oil developments, and in many cases fully nationalised the oil industry in their country. (Duval et al, 2009b).

3.2.3. Phase 3: Stability and growth in the ‘New World Order’

The period from 1986 to 2001 saw oil prices range between about 20 and 40 dollars per barrel (in 2015 dollars). Inflation had been brought under control and the 1990s saw strong economic growth. The period was also punctuated by major shocks ranging from a large stock market price correction in 1987 to the bringing down of the Berlin Wall in 1989 and subsequent collapse of the Soviet Union, the 1991 invasion of Kuwait by Saddam Hussein and subsequent military response by the United States and its allies, the Asian Financial Crisis of 1997, the Russian debt default of 1998 and the collapse of Long Term Capital Management, and the collapse of the dot-com bubble in 2000. The Iraq war disrupted 4.6 Mbpd of oil supply for 12 months, equivalent to 18 per cent of IEA countries’ oil imports at that time (Table 13 in section 6.1.1 of the appendices). In response, the first IEA collective action to release emergency stocks was initiated. In April 1999, OPEC cut oil production by 3.3 Mbpd for 12 months (Figure 50). Despite those financial shocks, and events, the oil market remained orderly and generally functioned well throughout the period.

In the 1980s, low oil prices prompted many governments to privatise their state-owned oil companies, led by governments in OECD countries, beginning in the UK with British Petroleum, British Gas and British National Oil Co, then in France with Elf and Total, Italy with Eni, Spain with Repsol/Hispanoil, and Canada with Petro-Canada.

3.2.4. Phase 4: ‘Return of history,’ Chinese super-growth, financial crisis and stalled growth

The terrible events of 11th September 2001 marked the end of optimism that characterised the period immediately following the end of the Cold War. A case can be made that those events, and the subsequent 2003 invasion of Iraq led by the United States,45 are as historically momentous and globally significant as the Middle East conflicts, wars and crises associated with the two oil price shocks of the 1970s. The 2003 Iraq war resulted in an oil supply disruption of 1.9 Mbpd for 1.4 months, which was about 6 per cent of IEA imports, (Table 13 in section 6.1.1 of the appendices and Figure 50). The earlier Venezuelan oil strike disrupted 2 Mbpd of supply for two and a half months. No IEA collective action was taken for either of those events, and throughout that period, the market continued to function without any significant problems.

The period following 2001 saw a return to oil prices in inflation-adjusted dollars equal to and exceeding the levels of the 1970s, followed by a crash to the real price level that prevailed between the two oil shocks. The 2015 average price was $52/bbl, compared with annual average prices (in 2015 dollars) from 1974-78 of $56, $51, $53, $54 and $51/bbl. The price continued to fall in early 2016, with spot prices bottoming below $30/bbl—a level equivalent to the annual average prices in the second half of the 1980s and the 1990s—before returning to just below $50 by mid-year. The increases in prices from 2001 to 2008, and again from 2009 to 2011, were very steep, but not near-vertical as in 1974 and 1979.

With the exception of the 2009 consumption decline (from 2008 levels) as part of the Global Financial Crisis, world consumption increased throughout the period. This contrasts with 1973-75 and 1979-83, when world consumption decreased as prices spiked. Consumption did not surpass the 1979 level until 1988, by which time oil prices were less than one-third of the inflation-adjusted 1979 level. The underlying trend throughout the period after 2001 was the growth of China’s consumption and imports. The decade between about 2004 and 2014 came to be known popularly in China as ‘the Golden Decade.’

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China produced 4.3 Mbpd of oil in 2015, 4.9 per cent of global production. This made China the fifth largest oil producer in the world behind the United States (12.7), Saudi Arabia (12.0), Russia (11.0) and Canada (4.4). But China also consumed almost 12 Mbpd, second only to the United States at 19.4 Mbpd, and almost as much as the entire European Union (12.7). China thus became the world’s largest oil importer for the first time with 7.7 Mbpd (not counting the EU as a country). It is easy to forget that China was an oil exporter prior to 1993, its oil exports peaking in 1985 and 1986 at 701 and 702 kbpd.

The underlying trend of China’s rapid large-scale economic growth is only part of the story of the years from 2001 to 2015. The period was also characterised by prolonged ground wars in Afghanistan and Iraq following the events of September 11, 2001. Countries from North Africa and across the Middle East, including a number of major oil producing countries, experienced unrest, revolutions and wars, and volatility continues to characterise the region. Although different from the wars and conflicts in the region during the 1970s and occurring within a different geopolitical context, it has arguably been a similarly unstable and uncertain time.

Again, despite these events, the oil market continued to function. Wars and conflict disrupted supplies from some countries, but Saudi Arabia continued to balance the market, albeit at ever-increasing prices, given the central role of prices in balancing supply and demand. The surge in United States onshore shale and tight oil production eventually pushed the market into over-supply. This followed similar over-supply conditions in the United States domestic natural gas (methane) market, the United States ethane market, and the United States propane and butane (LPG) markets.

As the oil market turned from tight to loose, OPEC and Saudi Arabia in particular faced a choice between forfeiting volume and market share to defend price, and forfeiting price to defend volumes and market share. Saudi Arabia chose the latter course, which has driven many United States shale producers into or close to bankruptcy.46 Some oil market analysts and commentators have also speculated that OPEC is ‘dead’ and that Saudi Arabia has forever lost its influence in the oil market. For example, in March 2011, ‘an independent energy market, policy, and geopolitical consulting firm’ operating from Washington, DC, London and Dallas, opened a note with the words: ‘We believe the 36-year era of OPEC oil price control ended in 2008…’ (Rapidan Group, 2011) and in May 2016, a writer at OilPrice.com began a piece entitled ‘OPEC is Dead: What’s Next?’ with this:

OPEC is dead, Rosneft’s head Igor Sechin has told Reuters. In a fine example of stating the obvious – at least to those who have been keeping an eye on the energy industry – and putting it in context, the chief of Russia’s largest oil company welcomed an era where the oil market will be driven by “finance, technology and regulation.” (Slav, 2016)

Plenty of column-inches have been written on this topic. We should pause to ask whether OPEC was also ‘dead’ during the 1980s and 1990s. Was OPEC ‘dead’ or ‘alive’ when it managed the posted price system it inherited from the Seven Sisters after 1973, when it implemented and gave up on netback pricing, or when it changed to benchmark pricing?

The quantitative analysis of data in this paper, including in section 2.2.4, together with the qualitative comparative analysis of the oil market in 2015 with the oil market of earlier periods suggests that OPEC is not ‘dead,’ nor has OPEC ever been as all-powerful as some commentators suggest. What is apparent is that OPEC is currently in a phase of defending market share, rather than supporting the market price, and this is neither new, nor surprising.

3.3. What can we learn from the 1970s?

The two oil price shocks of 1973-74 and 1979-80 were defining events in the world oil market. The desire to avoid a repeat of those events has influenced thinking about oil and security of supply since and continues to do so. Figure 49 neatly illustrates why those events made such an impression: they were by far the largest oil price shocks of modern times.

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Figure 49 Year-on-year changes in the nominal price of crude oil

Source: Author’s calculations using data from BP (2016).

The ‘oil shocks’ of the 1970s had a significant impact on the minds of policy makers, and the public, and have had a lasting impression on thinking about oil and energy security since. A number of valuable lessons can be learned from the 1970s. This rest of this chapter seeks to draw out the lessons and provides alternative perspectives to some of misplaced ‘popular wisdoms.’

3.3.1. Strategic responses of OECD countries to the supply shocks of the 1970s

Oil importing countries have available to them a wide range of policy options and strategies potentially available to them in response to uncertainty of supply and price, as shown in Table 5. Some options may only be available to some of the countries some of the time and a country may not wish to use all of the options available to it; some may be available but not relevant; and some involve a considerable time delay before they take effect.

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Table 5 Policy options and strategies available to importers in response to oil security challenges Response, grouped by categories deployed in the 1970s delay 2000s

Market-based approaches, with or without parallel government programmes

Allow the market to rebalance supply and demand N 10y Y

Use oil only where there are no practical alternatives (most notably: transport) Y 10y Y

Improve energy efficiency Y 10y Y

Use alternative fuels for transport N 15y+ ?

Explore, discover, develop and produce oil domestically and in other countries Y 10y Y

Emergency interventions to over-rule market mechanisms

Impose price and allocation controls on crude oil and refined products Y: US – N

Impose export controls on crude oil Y: US – N

Institutional measures at the national and international level

Establish a formal energy policy and supporting structures within government Y <1y Y

Form an association of oil importing countries to balance exporting countries Y <1y Y

Improve oil data and market transparency Y 5y+ Y

Geopolitical influence, leverage and power

Stabilise the Middle East through diplomatic and economic means Y – Y

Provide naval supervision of oil shipping lanes – – Y

Support or intervention to secure oil production N – N

Emergency reserves

Build and maintain emergency oil stocks Y 10y Y

Release oil from emergency stocks if required N 1mth Y

Source: based on the author’s research and analysis

At least ten of the fifteen policy options and strategies in Table 5 were implemented in response to the oil price shocks of the 1970s. Apart from the transport sector, substitute fuels in most countries have largely displaced oil, particularly in electricity generation. Energy efficiency in general improved at about two per cent per annum between 1973 and 1990, and by 0.9 per cent per annum in 16 IEA countries, between 1990 and 2005.47 Examples of 1970s policy responses include the Energy Conservation Program for Consumer Products and the Corporate Average Fuel Economy (CAFÉ) regulations in the United States, initiatives that have become an established part of the policy landscape. Conservation measures (e.g. thermostat adjustments) were generally short-lived, as they involve a reduction in service level and amenity; however, energy efficiency remains an important policy focus worldwide.

Transport energy efficiency has improved substantially and continues to improve. As discussed in section 2.1.16, the use of alternative transport fuels remains in its infancy: the fleet shares for LNG and CNG vehicles and for electric vehicles is still very low, although it is beginning to accelerate in some countries. The efficiency of the non-transport parts of the energy sector also continues to improve, and the energy intensity of economic activity continues to decrease, in the United States, Europe, Japan, Australia, China and elsewhere around the world. Energy efficiency and fuel switching measures naturally involve a time lag, and the effects of initiatives launched in the 1970s did not become clearly visible until about a decade after the first oil shock. Efficiency and fuel switching policies worked in concert with rising oil prices.

The response of the United States to the oil shocks also included the introduction of government control of oil allocation, and price controls on domestic oil production and on gasoline, but those measures tended to work against market forces balancing supply and demand. A ban on the export of crude oil was also imposed, although the United States was a net oil importer. Oil allocation controls and gasoline price controls were later lifted, followed by a lifting of crude oil price controls.

Direct military intervention was not used by the United States in the 1970s, and shipping lanes were not disrupted. Legislation was passed to establish emergency oil stocks, but emergency stocks could not be

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released, as they did not exist prior to the crises. There have been many diplomatic and economic efforts to improve political stability in the Middle East, with varying degrees of success. The United States Navy continues to supervise key oil shipping lanes, including the Straits of Hormuz and the Persian Gulf.

Since the 1970s, exploration and production have grown more rapidly outside the Middle East than in the Middle East. That new supply came to market in the 1980s, following the natural time lag for new developments. Since the 1980s, global oil supply and demand have largely been allowed to balance through the price mechanism. The oil supply disruption associated with the 1991 Gulf War—in response to the invasion of Kuwait by the then-President of Iraq, Saddam Hussein—remains the largest to date: 4.6 Mbpd for 12 months. The Kuwait Oil Company estimates that 80 per cent of oil wells were ignited by the retreating Iraqi army and associated oil infrastructure destroyed.48 Bechtel and an international team capped 650 damaged or burning wells in nine months.49

Following the 1970s oil shocks, the United States led the negotiation of an International Energy Program (IEP) Treaty under which the International Energy Agency (IEA) was established in Paris under the rubric of the OECD. Part of the IEA’s work involved the gathering and publication of improved data on oil production, trade and consumption. Since the late 1990s, that work has been enhanced through the Joint Organisations Data Initiative (JODI), which involves cooperation between APEC, Eurostat, the IEA, OLADE, OPEC and the UNSD.

In the 1970s, the United States developed a formal energy policy and established the Department of Energy and the Energy Information Administration as the key supporting structures within government. Almost all countries around the world today have some form of energy policy and ministerial accountability. The United States established the Strategic Petroleum Reserve (SPR) under the EPCA (1975).50 IEA member countries are also required under the IEP Treaty to hold oil reserves equivalent to 90 days of net imports, and their current and historical holdings are published on the IEA website.51 When emergency conditions are declared, IEA member countries meet to decide on whether to pursue collective action and release oil to the market from their strategic reserves.52 Section 3.4 on oil security discusses oil supply disruptions both recent and historical, the existing system of security, the objective of IEA collective action, stock draw and the IEA emergency reserves system in greater detail. With the benefit of hindsight, a number of policy errors are apparent in the responses to the first and second oil shocks, as summarised in Box 1 and Box 2.

3.3.2. Policy and market responses to the demand surge of the 2000s

Most, but not all, of the potential policy options and strategies available in the 1970s were deployed at that time, and the legacy of those decisions is evident today. The situation in the 2000s can be described as a mix of policies and measures that have continued from the 1970s, others that have been abandoned, and some new measures. The policy and market responses to the demand surge of the 2000s are discussed below.

While the sudden price shocks of the 1970s are usually linked with geopolitical disruptions to oil supply, the less sudden, but equally large price surge of the 2000s is commonly associated with the East Asian demand surge led by China. The prior decades of low oil prices resulted in low levels of investment in new production, which meant supply was hard-pressed to meet the surge in demand.

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Box 1 The first oil shock and policy lessons

ACIL Allen (2014, p.36ff) provides a good overview of the ‘first oil crisis,’ including contributing factors, consequences in the global market, and discussion of events in Australia. The consequences in the global market are summarised as follows:

— The oil market worked, notwithstanding OPEC market power.

— The oil price spiked to clear the market (avoid shortages) in the short-term.

— The United States was an exception, because the government tried to override the market with price controls and administrative allocation of oil and refined products

— Over the time, the market continued to work as high prices encouraged supply of additional quantities, and reduction of quantities demanded. The market adjusted down prices as these efforts succeeded.

The report describes the mechanism by which OPEC countries were able to exercise market power, capturing a higher share of available oil resource rent:

‘OPEC exercised market power by repudiating agreements and ratcheting-up prices by creating fear, raising production taxes to support higher prices, cutting production, creating more fear, raising taxes again, and repeating the fear and tax cycle.’

In response, speculative demand played a significant role in the first oil shock. The severity of the shock was exacerbated by a number of policy errors. Before October 1973:

Oil prices had been kept at levels too low to restrain demand and stimulate investment

There was increased concern about the level of employment and central bankers felt the responsibility to stimulate employment by loosening monetary constraints, even if that perhaps meant some moderate inflation.

Major shifts in monetary policy in many OECD countries in the early 1970s led to a ‘dramatic increase in worldwide liquidity’ (Kilian, 2010)

The aggregate demand shock resulted in production levels close to capacity in the Middle East and globally.

By July 1973, three ‘phases’ of general price controls had been tried and failed in the US.

‘Phase IV’ price controls were implemented in August, directed at the oil industry, price discriminating between ‘old’ and ‘new’ oil, and causing many unintended consequences.

OAPEC producers took the opportunity to exploit their market power. Production cuts ostensibly made to advance Arab interests in an ongoing conflict with Israel were actually a means of exercising potential market power. After October 1973:

The United States Emergency Petroleum Allocation Act (EPAA) authorised price, production, allocation, marketing and export controls. The Act was drafted, debated, passed and signed into law 42 days after the Arab Oil Embargo was announced.

Administrative allocation of fuels resulted in widespread chaos, protests, threats of strikes and extensive queuing.

‘The Netherlands, which was also subject to the embargo, did not experience shortages that had to be resolved by queuing. The chaos in the United States was caused by price controls and administrative allocation.’

Source: ACIL Allen (2014), author’s research

In response to the initial price shock in the 1970s, a substantial share of oil demand was able to find substitutes to oil, particularly in the power sector and industry, as well as to improve the efficiency of remaining oil demand in other sectors. Following the price surge of the 2000s, substitution away from oil was much more difficult. Substitutes in the transport sector, such as natural gas vehicles and electric vehicles, are yet to made anywhere near the impact of the switching from oil to coal, gas and nuclear power in the 1980s and 1990s.

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Box 2 The second oil shock and policy lessons

In 1976 a decision was made by the IEA Governing Board to build stocks in the lead-up to and throughout what turned out to be the second oil crisis:

The Governing Board (b)

(1) noted the Standing Group on Emergency Questions’ (SEQ) report on the emergency reserve commitment, set forth in IEA/SEQ(76)4(3rd Revision) and Corrigendum 1;

(2) concluded that the International Energy Program group would be in a position to achieve, albeit with some degree of difficulty, the target of 90 days’ emergency reserves by 1980 (although one or two Participating Countries might need a further one or two years) provided that international marine bunkers and naphtha would be treated according to the provisions of (d) and (e) below;

… (3) decided that on 1st January, 1980, the emergency reserve commitment referred to in Article 2.2 of the I.E.P. Agreement shall be raised from 70 to 90 days but that, according to the provisions of (d) and (e) below, naphtha for uses other than motor and aviation gasoline, and international marine bunkers, will not be included in the consumption against which stocks are measured;

(4) decided that, in order to avoid an adverse impact on the oil market of the incremental oil demand for stock building, Participating Countries should ensure that the build-up of emergency reserves is spread as evenly as possible over the period and noted that in this connection the following annual steps were suggested as an illustration of how the objective could be met: 1st July, 1976 70 days 1st July, 1977 76 days 1st July, 1978 82 days 1st July, 1979 88 days 1st January, 1980 90 days

This required the addition of 6 days of imports each year to the stock levels of (in descending order of 1979 import volumes) the United States, Japan, Germany, Italy, Spain, the Netherlands, Sweden, Belgium, Denmark, Turkey, the United Kingdom, Switzerland, Austria, Greece, Ireland and Canada. In terms of volume, this required about 145 million barrels of additional oil imports per year by July 1st in each of the years 1977 to 1979, which was about 1.2% of the world import market of about 34 Mbpd at that time, plus a further 42 million barrels by the beginning of 1980.

Additional demand of 1.2 per cent of the import market does not sound like very much. However, it is equivalent to 400 kbpd (spread evenly over the year), which is greater than the export level at that time of Kuwait, and is approaching the export level of Qatar or Oman. In other words, it was equivalent to an entire OPEC gulf state exporter.

It must also be recalled that—as a result of events in Iran and then the Iran-Iraq war—at the time the stock building was decided upon, Iran’s oil exports went from 5.1 Mbpd in 1977 to 4.7 in 1978 to 2.5 in 1979, 888 in 1980 and 736 in 1981. Iraq’s oil exports initially increased from 2.4 Mbpd in 1977 to 2.6 in 1978 to 3.5 in 1979, before falling to 2.7 in 1980 and 907 in 1981.

The IEA Governing Board requirement to build emergency oil stocks to the 90 day level between 1976 and the beginning of 1980 would appear to have been a material contributor to the market tightness and the high oil prices of the second oil shock experienced at the end of that period.

Furthermore, Adelman (1995) stated that ‘[E]arly in 1978, the governments of the United States and Saudi Arabia entered into an agreement that Saudi Arabia would maintain oil output and the United States would not purchase oil for its Strategic Petroleum Reserve. The agreement was not announced at the time.’ It is not clear how the United States reconciled the 1976 IEA Government Board decision and its 1978 agreement with Saudi Arabia.

Sources: Item 20, Decision to Raise the Emergency Reserve Commitment to 90 Days, 8-9 November 1976, IEA/GB(76)53, Item 2(b) pp.93-94 in Richard Scott (1995) IEA—The First 20 Years: The History of the International Energy Agency 1974-1994; Volume Three: Principal Documents, Paris; ACIL Allen (2014)

3.3.3. Lessons of the 1970s for OECD countries

What the above analysis indicates is that the oil shocks of the 1970s were the catalyst for far-reaching demand-side responses, which had the combined effect of radically reducing the growth trajectory of oil consumption. OECD countries learned that the demand-side is at least as important as the supply-side in

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influencing the oil market. The legacy of that lesson has continued through the decades to the present time in the form of initiatives by governments, utilities, manufacturers and consumers to improve energy efficiency and to switch fuels in cases where it is appropriate and economic to do so.

The 1970s also demonstrated that attempts to resist market forces with regulation are rarely successful. Price controls and rationing go hand-in-hand and work against both the supply and the demand sides of the market from responding to the price signals that would otherwise take place. The absence of price signals leads to underinvestment on the supply side, as well as disincentives to improve efficiency and seek alternative energy sources on the demand side. The 1970s demonstrated that attempts to resist market forces with regulation are rarely successful and tend to be counter-productive. The legacy of that lesson continued through the 1980s and 1990s as the oil market developed and matured, and has remained relevant to the present day.

Related to the lesson on the ineffectiveness of price controls are lessons on the balance of sovereign powers relating to money, inflation and exchange rates, and host country shares of natural resource rents. Runaway inflation in the 1970s devalued the US dollar, and undermined the system of posted oil prices fixed for substantial periods of time in nominal terms. With a floating United States dollar no longer exchangeable for gold after the 15th of August 1971, it was no longer feasible for oil prices to be fixed. Similarly, US dollar inflation presented a serious problem for oil exporting countries, given that the dollar was the international vehicle currency for oil trade. By the early 1980s, these lessons had been absorbed and implemented in Washington. For example, after being sworn on as the 40th President of the United States on January 20th 1981, President Reagan decontrolled oil prices on the 28th. Withdrawing by Executive Order the Emergency Petroleum Allocation Act of 1973.

Experience demonstrates that a tight market will eventually become a loose market and a loose market will eventually become a tight market. The oil market is no exception to this, and the economic forces that drive the price cycle were at work during the high price periods of the 1970s and the 2000s. The oil market was tightening through the late 1960s and into the early 1970s, well before the ‘crisis’ or shock. However, it was not widely recognised at the time, because the usual signal of a tightening market (increasing prices) was obscured by regulated prices that were fixed in nominal terms. Following the delayed investment that occurred in response to the eventual high prices, along with the other market and policy responses to the crises of the 1970s, the market loosened again through the 1980s and 1990s. The market then tightened again in the 2000s, and has loosened again since 2014. The same lesson is being learned again today, with the boom of shale oil and the subsequent oil price collapse.

The supply of oil was never going to ‘run out’ and the supply of oil will never be exhausted as long as markets are allowed to work. There is also a need to allow the market to rebalance; this means that the price paid by consumers should reflect the market price. If government or regulatory policies or actions distort the true market price, then more severe imbalances will tend to arise. Higher prices will always stimulate new supply, moderate the price increases from higher levels of demand. As the economy grows, consumers are able to afford higher real prices, which may even constitute a smaller share of GDP than did earlier lower real prices. That has consistently been the experience since the 1970s, even during the price surge of the 2000s. The increasing affordability of higher real prices offsets the trend of increasing marginal costs as low-cost resources are gradually depleted.

3.3.4. Lessons of the 1970s for OPEC countries

The OPEC countries also learned a number of lessons from the experience of the 1970s. The oil exporters found that the supply side has an important influence on the oil market. The legacy of this is felt to the present day in the leverage of host governments over international oil companies, particularly when the market is tight, and their ability to secure a significantly larger share of natural resource rents than was the case prior to the 1970s.

Nevertheless, the exporters ultimately learned that a producer can defend price or market share, but not both at the same time. That lesson was strongly reinforced in 1983, when OPEC considered production cuts, but realised they would not be effective. The lesson was reapplied in 2015, when Saudi Arabia realised it could no longer defend prices without sacrificing market share and revenues.

The price-or-market share lesson leads to the next lesson, which is that the response of consumers to price increases and decreases is asymmetric (Dargay and Gately, 2010). When oil demand goes elsewhere in

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response to oil price increases—particularly as a result of intentional withholding of supply by producers—not all of that demand returns in response to later price decreases.

Cutting off supply to one’s customers provides a short-term ‘sugar hit’ in the form of much higher prices and higher revenues than before the disruption. However, such tactics permanently destroy long-term demand, and also tend to permanently stimulate alternative, competing sources of supply. With the benefit of hindsight, it is clear that by the 1970s, a reduction in the rate of growth of global oil demand had clearly become necessary. Nevertheless, oil exporters felt the pain of the 1970s oil demand destruction and the stimulation of alternative sources of supply that flowed to market in the 1980s, leading to a prolonged period of low prices, and the challenges of defending market share.

Just as oil importers learned that a loose market creates the conditions for a tight market, so the oil exporters learned that a tight market creates the conditions for a loose market later. Likewise, oil exporters learned the lessons of energy efficiency and alternative energy sources. In response to a sufficiently prolonged period of high prices, in the medium- to long-term customers will go elsewhere, through other sources of oil supply, other sources of energy, and more energy efficient technology.

Flexible spare capacity remains rare in the oil market, and continues to play a vital balancing role. The 1970s certainly demonstrated the market power that comes from monopoly control of the only flexible spare capacity. However, the lessons that followed the 1970s also demonstrated to the oil exporting countries the dangers of irresponsible use of that market power. In a sense, that lesson is the mirror image of the lesson that issuing a global reserve currency is an ‘exorbitant privilege’ and that the combination of high inflation and fixed nominal prices leads to a build-up of financial pressure, and political frustration, which tends to lead to a crisis.

3.4. Oil security

The IEA defines energy security as ‘the uninterrupted availability of energy sources at an affordable price’ (IEA, 2014). Energy security is conceptualised as the result of reliable/uninterruptible supply, affordable/competitive supply, and accessible/available supply. The framework can be applied to oil security specifically, as well as to energy security more generally; for example, energy security is enhanced by the ability of other fuels to increase supply in situations where oil supply is reduced. Such temporary replacement or ‘fuel switching’ reduces oil demand, as does demand restraint. On the supply side, the responses to increase supply involve either production surge from spare capacity or stock-draw.

3.4.1. Oil supply disruptions both recent and historical

Figure 50 shows the timeline of disruptions to oil supply since World War 2 in terms of magnitude, frequency and duration. The disruptions are colour-coded according to the cause of the disruption, following the classification system of Beccue and Huntington (2005). The three occasions when an IEA Collective Action has been taken are labeled. The only major disruption for which an IEA Collective Action has been taken was following Iraq’s invasion of Kuwait. The Libyan Revolution of 2011 and Hurricanes Katrina and Rita are among the smaller disruptions, although those events coincided with tighter market conditions than prevailed during larger disruptions since the 1970s. The first part of Figure 50 shows the disruptions in absolute volume terms. The second part shows the disruptions as a percentage of OECD imports.

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Figure 50 Timeline of oil supply disruptions and IEA collective actions

Sources: Author’s chart from data in Beccue and Huntington (2005), Table E.1, p.55, updated with disruptions since 2005.

Table 13 in section 6.1.1, Oil supply disruptions since 1950 on page 133 of the Appendices provides the details on each of the disruptions shown in the figures.

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3.4.2. Market responses to supply shocks including speculative demand shocks

There will be a natural market response to any market disruption. All else being equal, a supply disruption will lead to an increase in price, which will tend to stimulate a demand response in the form of both demand restraint and fuel switching, and a supply response through increased production and drawdown of oil in commercial storage facilities. Those ‘textbook’ market responses ‘absorb’ the shock and moderate its severity.

However, unless a supply disruption occurs without any warning and is a complete surprise to the entire market, the market response begins in advance of the supply shock itself in the form of ‘speculative demand.’ Consumers seek to secure supplies; companies increase inventories; and traders buy and store oil. Hence, a supply shock will usually induce a ‘speculative demand shock,’ which tends to magnify the severity of the supply shock, and may prolong its effect. ACIL Allen (2014) provides numerous examples of such speculative demand shocks, together with explanations of the chain of events in a number of historical cases:

the ‘repudiation of agreements’ and the Yom Kippur Arab-Israeli War, 1973-74

the Iranian Revolution and the Iran-Iraq War, 1978-80

the withdrawal of Saudi Arabia’s support for the oil price, 1985-86

Iraq’s invasion of Kuwait, 1990-91

the Venezuelan oil supply crisis and Iraq War 2002-03, and

‘multiple shocks’ 2003-14

The report summarises as follows:

Until a decade ago, the conventional view was that major price spikes were caused by major exogenous supply shocks. This view not only overlooked the existence of the persistent supply shock…but also ignored the importance of aggregate demand shocks and speculative demand shocks, and potential contributions from oil producers restraining production to take advantage of higher prices later (forms of speculative supply or demand shocks). It is now widely recognised in the relevant economics literature that various types of shocks have often occurred in close proximity in time and that the mix of shocks has varied between major oil price events. (ACIL Allen, 2014, p.126)

An interpretation of the ‘persistent supply shock’ described by ACIL Allen is that Saudi Arabia and other Middle East producers reserve some flexible spare capacity, which they can ‘swing,’ to perform the essential function of balancing the global oil market. This is discussed further in section 3.5.8: how shale oil interacts with spare capacity and other means of balancing the market.

Release of emergency stocks is only relevant in the case of a ‘supply shock’: i.e. a supply disruption whether in upstream production, midstream in the transport chain, or downstream in the refining complex. IEA emergency stocks would not be released for an aggregate demand shock. A ‘price shock’ through the exercise of producers’ market power to raise the price would be expected to require some form of supply shock. In the 1973-74 oil shock, the mechanism for ratcheting up the price involved sequential withholding of capacity (supply disruption). However, that episode was also preceded by a significant aggregate demand shock that had not yet been reflected in prices.

In practice, the degree of short-term flexibility in the oil market is relatively limited, so short-run price movements tend to be proportionately much larger than demand and supply adjustments. In economic terms, neither supply nor demand are very elastic in the short-run. (Price elasticity is discussed above in sections 2.2.8 and 2.2.9). However, history shows that the market does respond over time if it is allowed to work. Since at least 1993, the IEA has emphasised free market issues, ‘reflected in the IEA’s work on deregulation, reduced government interventions in markets (particularly with respect to price), privatization, greater competition, and increased productivity of undertakings in the energy sector’ (Scott, 1995b, p224).

3.4.3. The role of market prices and price volatility

Luciani (2010) observes that oil price volatility is a challenge for all: producers and consumers, exporters and importers. Volatile prices mean that oil exporting countries face unstable revenues, companies face uncertainty in investment decisions, and during upswings in the price cycle consumers pay higher prices than would be necessary to stimulate supply. On the downside of the cycle, prices are discounted to clear the market, so that consumers pay prices that may be insufficient to stimulate supply in the long run.

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Under-investment leads eventually to lack of supply, which leads to prices again exceeding the long-run marginal cost supply later, when the cycle repeats.

Oil price volatility is fundamentally caused by the price rigidity or inelasticity of oil supply and oil demand in the short-term. Futures markets reveal volatility to a greater extent than would be the case if trading was limited to bilateral physical contracts. But market volatility provides forward-looking signals of imbalances between supply and demand that may otherwise not be as apparent. As noted in section 2.1.13, futures and options markets allow the management of price risk through ‘hedging.’ Producers and consumers can ‘lock in’ a particular future price. For the cost of a ‘put option’ premium, producers can protect themselves from price decreases in the future, without foregoing the opportunity to benefit from future price increases. For the cost of a ‘call option’ premium, consumers can protect themselves from price increases in the future, without foregoing the opportunity to benefit from future price decreases. The buying and selling behaviour in those derivatives markets provides valuable information for all market participants.

3.4.4. The IEA system of oil supply security and Australia’s experience

The IEA’s emergency response system is the only multilateral framework and mechanism for IEA member countries to coordinate various national and common measures and collective action on release of emergency stocks, with the purpose of complementing the responses of the market in dealing with supply disruptions. The system includes supply-side measures and demand-side measures, as shown in Figure 51. The two categories of demand-side measures are fuel switching and demand restraint. The two categories of supply-side measures are a domestic production surge and stockdraw.

The IEA states that:

The primary purpose of an IEA collective action is to mitigate the economic damage associated with a disruption of oil supply. By temporarily replacing disrupted supplies, the action is intended to help oil markets re-establish the supply/demand balance at a lower price level than would otherwise have been the case. (IEA, 2014, Box1.2, p.20)

The IEA Emergency Response System is activated through a ‘collective action’ agreed upon by the member countries. It should be noted that the IEA Collective Emergency Response Mechanism (CERM) is a last resort and it has only been used on three occasions since it was established. When a collective action is proposed, representatives from the member countries are required to make a judgment on whether the market should be left to adjust itself or whether IEA member countries should intervene by making emergency stocks available. This is not an easy decision, and prior to a decision, the possibility of an IEA collective action increases market uncertainty.

In Australia, the market mechanism has always been relied on to balance supply and demand. Neither the 1973-74 nor the 1978-80 first and second oil crises generated liquid fuel emergencies. The market system effectively avoided shortages and prices adjusted to circumstances to clear the market. Australia joined the IEA in 1979. In 1990-91:

There was consumer response to higher fuel prices, lower economic activity, and perhaps publicity about the need for energy conservation. These factors resulted in a decline in consumption of petroleum during and after the oil shock. The decline in consumption and an increase in production from domestic refineries allowed Australia to reduce its imports and meet its IEA obligations to reduce its call on global oil supplies. Australia did not encounter a supply obligation under the IEA arrangements as a result. While there was a decline in consumption, at no time was a fuel shortage experienced, and no interventions by governments were necessary. The situation did not reach the stage where a National Liquid Fuels Emergency had to be declared.53 (ACIL Allen, 2014, pp.84-85).

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Figure 51 The IEA Emergency Response System

Source: IEA (2014, Figure 1.7), p.21

In Australia, market price-induced demand reductions and very light handed demand restraint have been sufficient to maintain market balance and avoid emergencies through supply shocks.

3.4.5. The role of spare capacity

The ability to deliver a production surge to respond to a supply disruption elsewhere requires spare production capacity that had been held in reserve prior to the disruption. The IEA defines spare capacity as ‘the capacity levels that can be reached within 30 days and sustained for at least 90 days’ (Stelter and Nishida, 2013, p.25). The United States EIA uses the same definition (EIA, 2016). Most of the world’s spare oil production capacity is held by OPEC, and is concentrated in a single exporter, Saudi Arabia. In contrast, the scope for a ‘production surge’ from increased indigenous production among IEA countries is very limited.

The advent of light tight (shale) oil in the United States has changed the dynamics of oil supply, but new shale oil production cannot be brought to market sufficiently rapidly to meet the IEA definition of spare capacity referred to above. Recent historical data shows that there is a delay of 15 to 22 weeks from a turning point in oil prices to a turning point in horizontal drilling rigs in North America. Given the process of drilling, fracking and completing a shale well, it then takes at least four to six months to bring into production oil from new shale wells. Hence the response horizon for shale oil is up to one year, and the experience so far suggests shale oil is well suited to balancing in a one- to five-year forward time frame. This is not as responsive as flexible spare capacity that can respond within 30 days and then sustain output for at least 90 days. Shale oil is not ‘spare capacity’ and nor is it a new source of ‘swing production.’ However, shale oil is far more responsive than large-scale conventional oil projects, for which the response time is typically be five to ten years. The ability of shale oil supply to contribute to oil market balancing is a new development, which tends to reduce pressure on other supply-side sources of market balancing, including flexible swing capacity.

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Figure 27 in section 2.2.3 shows that in the 1970s and 1980s, Saudi Arabia’s annual average daily production rate swung enormously three times—by 5.4 Mbpd up, 6.6 to Mbpd down and 5.2 Mbpd up—each time within the space of several years. Since 1990, Saudi annual production has swung through a range of 2 Mbpd, while underlying Saudi production has grown from 9 to 12 Mbpd. Section 3.5.8 on page 96 describes in more detail how shale oil interacts with spare capacity and other means of balancing the market.

3.4.6. The objective of IEA collective action contrasts with OPEC’s publicly-stated objective

Following the statement of the objective of an IEA collective action quoted above, the IEA in effect acknowledges the risk of ‘fighting’ or counteracting normal market forces (IEA, 2014, Box1.2, p.20):

Managing oil prices is not the purpose of an IEA collective action, however, as high prices can have underlying causes which temporary emergency measures cannot address. Moreover, attempting to manage prices with emergency measures risks masking important market signals, such as the need to invest in supply infrastructure or more fuel efficient technologies, which are essential to assuring supply security in the future.

There is the risk of an internal inconsistency, or at least a degree of ambiguity, in the objective statement, in that a collective action is intended to help oil markets rebalance at a lower price level than would otherwise have been the case, but without managing prices. It should be recognised that the oil market, as is the case with all markets, is almost never perfectly ‘balanced’, but is rather in constant movement from one imbalance to another. The daily volatility of oil prices is but one indicator of this dynamic.

The IEA’s statement that collective actions are not intended to manage oil prices contrasts with OPEC's publicly stated objective ‘to secure fair and stable prices for petroleum producers.’ (The full OPEC objective is in section 2.2.4). Distinguishing between ‘normal’ market imbalances that can be left to the market (or to OPEC) to resolve, and disruptions that would cause economic damage and warrant an emergency response, is not necessarily straightforward, as discussed below in section 3.4.8.

3.4.7. Stockdraw and the IEA emergency reserves system

The form of IEA emergency stockholdings varies across the member countries, and includes industry stocks, government stocks, stocks held overseas on behalf of the member country, and combinations of these forms. The IEA summarises the process by which emergency stocks may be drawn down in an emergency as follows (IEA, 2014):

The exact method of emergency stocks release varies considerably among IEA countries. In practice, the preferred approach in most countries that impose all of the stockholding obligations on industry operators is a uniform reduction in the stockholding obligation by a certain percentage or by a specified number of days of supply. In general, these volumes are made available through the normal channels at market prices. By contrast, Luxembourg convenes a committee of government/industry representatives to determine the release and pricing of obligatory stocks. In Switzerland, the release would be allocated according to individual company needs.

A variety of approaches is also used for the release of government/agency stocks. Several countries would conduct the release from public stockholdings through a tender bidding process (Germany, Japan, the Netherlands, Poland and the United States). Most other countries would make the stock available at prevailing market prices (the Czech Republic, Estonia, Finland, France, Hungary, Ireland, New Zealand, Portugal and Spain). In the Republic of Korea, the government determines the pricing of the release from its stockpile. The Czech Republic, Finland and the United States are examples of countries that sometimes release public stocks in the form of loans.

IEA collective action remains the exception rather than the rule in the oil market. IEA collective actions have been initiated on just three occasions in 40 years:

1. Prior to United States–led action following Iraq’s invasion of Kuwait in 1990 2. Following the back-to-back Gulf of Mexico hurricanes Katrina and Rita in 2005 3. In response to supply disruption related to the Libyan Revolution in 2011

As Figure 50 on page 74 shows, there have been many more oil supply disruptions for which no IEA collective action was initiated. There were also supply disruptions prior to the 1970s, before the existence of the IEA or the emergency reserve system. In those cases imbalances arising from supply disruptions were resolved by market mechanisms.

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3.4.8. The role of the IEA in view of the development of the market

Continuing from the text quoted in section 3.4.6 above, explaining the primary purpose of an IEA collective action, IEA (2014) explains:

At the time the IEA was created, policy makers were primarily concerned with the physical unavailability of oil supplies and sought to define a threshold for activating an emergency response based on a specified volume of disrupted oil supply.

It is significant that the IEA was created just after what turned out to be the end of the regulated oil price era, and the beginning of the market era. Continuing, IEA (2014) notes this point:

Oil markets have changed enormously since the first oil shock of 1973-74. As a result of the liberalisation of the oil industry and the development of spot and futures markets, changes in supply and demand are quickly reflected in the international market prices of crude oil and refined products. Increases in spot prices quickly feed through into higher retail prices and the very notion of a “supply shortfall” is misplaced: a reduction of supply would cause prices to rise immediately whilst higher prices would lead to lower demand and bring the market back into balance.

Emergency Responses are policy actions intended to complement natural market responses. However, there is an ever-present risk that emergency responses may counteract desirable market responses, thereby exacerbating or prolonging the adverse effects of a shock. In any given situation, the interactions between policy actions and market responses will be complex, influenced by expectations of future behaviour by multiple parties including governments of oil exporting nations, governments of oil importing nations, some of whom are IEA members, companies, businesses, traders and consumers. Expectations of future prices are also an important part of the dynamic.

The changes over the four decades since the emergency response mechanism was designed have resulted in a far more sophisticated oil market. As a result, the decision on whether to intervene with an emergency response is all the more difficult. The next section describes some of the changes and developments in the oil market since 1973-74.

3.4.9. Changes and developments in the oil market

Figure 52 illustrates the nature and significance of the change in the oil market that occurred between the end of 1973 and the beginning of 1974. Note that the scales are different between the left and right hand charts in Figure 52.

Up to the end of 1973, the nominal oil price changed in a series of steps. With the nominal price fixed at any moment in time, the real price was eroded by inflation, before a regulatory step change (usually an increase). Nevertheless, from the late 1950s until late 1973, the real oil price was in steep decline, punctuated by several increases.

The first oil price shock in late 1973 occurred just before the end of the regulated price era. The second oil price shock in 1979 occurred in the early years of the market price era. The second shock was larger than the first in nominal terms, but similar in real terms.

The first oil shock returned the real oil price to about the 1965 level. The second oil shock returned the real oil price to the level of 1957. The price collapse of the 1980s and 1990s resulted in real prices around the level of the late 1960s and early 1970s. The price surge of the 2000s returned real oil prices to the levels of the late 1940s and early 1950s.

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Figure 52 The price of crude oil in the regulated and market eras before and after 1974

Note: log scale. Source: Ron Alquist, Lutz Kilian, and Robert J. Vigfusson, ‘Forecasting the Price of Oil,’ in Graham Elliott, Allan Timmermann (Eds) Handbook of Economic Forecasting, Volume 2, Part 1, p.431

The nominal price volatility from 1974 onwards is evident in Figure 52 and contrasts strongly with the step-wise nominal price changes before 1974. However, the pattern of real price declines from the late 1950s to 1973 display a similar pattern to the real price declines from 1980 to late 1999, although the scales are different.

Although prices were nominally stable before 1974, real prices were not.

Throughout the late 1970s, there was a price discrepancy in the United States between the domestic and imported oil prices (visible in the right hand side of Figure 52), as government policy tried to resist market forces, unsuccessfully, as it turned out. The policy settings resulted in rationing and significant economic

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and political problems (such as queues for gasoline at filing stations) and were abandoned early in the next decade.

Having noted that the very notion of a ‘supply shortfall’ is misplaced, the IEA (2014) notes the inelastic nature of oil demand:

However, this rebalancing might require prices to increase substantially in response to a relatively small fall in supply, given the high concentration of oil use in the transportation sector where few short-term alternative options exist. (IEA, 2014)

Supply is also inelastic in the sense that there is a time lag between a price signal and a change in supply, given the times needed to bring on new supply. On the other side of the price cycle, the dominance of fixed costs (most of which are ‘sunk’ at the time of investment) means that most oil production does not reduce its output when prices fall.

The IEA goes on to explain the purpose of a collective action, drawing a fine distinction between stabilising the market and managing prices:

In the absence of price controls that might cause physical shortages, a sudden fall in global oil supply can cause economic damage through sudden price increases. The purpose of an IEA collective action is to limit the extent and impact of a sudden fall in global oil supply caused by a disruption. In such instances, IEA countries would want to replace lost supplies on a temporary basis in order to prevent economic damage, but they would still allow the market to set the price. Such a move is best described as an effort to stabilise the market rather than to manage prices. (IEA, 2014)

The market has rebalanced on many occasions by the usual market forces and the price effect.

It has been observed (Kilian, 2009b), that ‘…the increase in real activity in 1973 predated the increase in the real price of oil; in fact, it started in late 1971. The reason for the asynchronicity, as discussed in Robert Barsky and Kilian (2002) and Kilian (2008), is that the price of crude oil before late 1973 was not determined by market forces and remained below its market-clearing level. Had the price of oil been free to move, it would have risen much earlier, in line with other industrial commodity prices.’ The same author notes that ‘…there is good reason to be skeptical of the assertion [by Hamilton, 2009] that oil supply shocks were the primary explanation of all oil price shocks before 2007-08.’ Figure 53 shows the deviation of the real oil price from a long-run mean, and the deviation of global real activity from its long-run trend.

Kilian (2009b) explains that ‘commonly used measures of exogenous oil supply disruptions explain at most about 20 per cent of the observed increase in the real price of oil in 1973-74’ and that alternative measures that he has proposed ‘imply even lower estimates of the predictive power of exogenous oil supply shocks.’ Shifts in the demand for oil explain the remaining 80 per cent (or more).

Figure 53 shows that ‘not all movements in the real price of oil were associated with swings in real global activity, but the three major oil price shock episodes of 1973-74, 1979-80, and 2002-08 all coincided with major surges in global real activity.’

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Figure 53 Global real activity and the real price of oil, 1973-2008

Source: Kilian (2009b). a. Price is deflated by the United States consumer price index b. Update of the measure described in Kilian 2009a.

3.4.10. Valuing oil security

The case for emergency reserves or strategic storage has been made in qualitative terms on the grounds that it is a ‘public good,’ without attempting to quantify the value or to justify the cost to the public in terms of the benefits (see for example, Jaffe and Soligo, 2002).

The IEA recently sought to quantify the value of oil security, or more specifically, the value of the IEA emergency stocks and the economic benefits of the IEA emergency reserve system. Figure 54 shows the simulation framework from the Oak Ridge National Laboratory (ORNL) study used as the basis for estimation of benefits by Stelter and Nishida (2013).

The IEA paper brings together a study on oil storage costs by the Dutch consultants Downstream B.V. and computer modelling of the benefits of oil storage by ORNL. The costs of oil storage are dominated by the purchase cost of oil and the holding cost of oil, which are driven by the oil price and the rate of interest, respectively. Construction and maintenance of the physical storage and related infrastructure are also taken into account. The benefits of oil storage are dominated by the avoided cost of oil purchases following a supply disruption, and the avoided GDP losses resulting from a disruption of oil supply, with benefits from those two categories being about the same size.

Modelling of the benefits is considerably more complex and involves more uncertainties than the calculation of the costs of oil storage. The IEA paper is based on the 2011 oil price of US$108 per barrel and a discount rate of 3 per cent per annum, which results in a high estimate of benefits.

The key inputs used to model the benefits include the magnitude, duration, and probability of disruptions, the price of oil, the discount rate used, whether producers (most notably Saudi Arabia) use spare capacity to increase output, and the threshold or disruption magnitude specified for the drawdown of strategic stocks.

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Figure 54 Benefits of Emergency Oil Stocks: Simulation Framework

Source: Leiby et al (2013), slide 5

In the ORNL work, disruption probability distributions reported in Beccue and Huntington (2005), based on the history of significant disruptions to oil supply since 1950 (up to 2005), were used as the basis for Monte Carlo simulations. The probability distributions were developed collaboratively by a group of experts including the ORNL team with the Stanford Energy Modelling Forum (EMF). The historical disruptions are shown in Figure 50 on page 74 and Table 13 on page 133 of the Appendices, which also indicates the instances of IEA collective action enabling the drawdown of oil from the emergency reserve system.

Monte Carlo simulations with and without the use of emergency stocks provided the basis for estimation of the direct and indirect benefits of emergency oil stocks. Across the range of simulations there is a wide range of outcomes, as also shown in the 2013 IEA paper.

3.4.11. Estimating the probabilities, magnitudes and durations of future disruptions

In 2015 Beccue and Huntington (2015) updated the 2005 study referred to above and used in the 2013 IEA paper, using a similar methodology involving influence diagrams, disruption probabilities and expert panel input. The updated assessment covered five regions of the world: Saudi Arabia, Other Persian Gulf, Africa, Latin America, and Russian / Caspian States. Taken together these regions account for 57 per cent of the world production of 98 MMBD (as projected by the U.S. Energy Information Administration for 2020). The update explicitly considered disruptions at choke points of vulnerable shipping lanes, updated probabilities to reflect current world conditions, and modified excess capacity and oil supply forecasts. Both the 2015 and 2005 reports focused their ‘effort specifically upon geopolitical, military and terrorist causes for disruptions outside the United States.’ Not included in the assessment were geopolitical disruptions from the United States market and smaller global producers. Excess capacity was considered as a source to mitigate oil disruptions and therefore a primary output of the assessment is “Net Disruptions” or the total disruption less the excess capacity available. The study defines a disruption as:

A sudden shortfall in oil production from a world supplier that could potentially cause 2 [Mbpd] to become unavailable within 1 month of the beginning of the disruption. After the period, world production recovers to the same level prior to the shortfall. The disruption occurs at least one time during the 10-year period 2016-2025.

The objectives of the study were: (1) to develop a risk assessment framework and utilise expert judgment to develop the overall probability of a major oil disruption, (2) characterise the likelihood, effective

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magnitude, and duration of potential supply disruptions; and (3) clearly document the logic and assumptions driving the risk analyses. From the report: ‘This risk assessment is part of a larger project initiated by the [United States] Strategic Petroleum Reserve Office to evaluate the benefits and costs of maintaining, expanding and using public oil stockpiles. It addresses only one of many critical issues in the SPRO analysis. By itself, it does not determine what the appropriate strategy should be. Nor does it cover all the important considerations that influence those decisions.’

Figure 55 World Oil Disruption Influence Diagram

Source: Beccue and Huntington (2016), Figure 1, p.9.

Figure 55 shows—in the form of an influence diagram—the risk assessment framework developed. The study team entered detailed probability data obtained from the experts into a decision and risk analysis software package. To obtain summary information, the authors calculated the disruption size for all combinations of event states (millions of scenarios) and weighted each scenario by its likelihood of occurrence. The study includes scenario-probability pairs that are summarized and displayed in an Excess Probability graph. This graph is shown for all disruptions of three different durations in Figure 56.

Table 6 shows the assessment variables from the influence diagram in the order they were assessed. Beside the table on the right are the disruption probabilities by region, for disruptions of short, long and very long durations, calculated by the authors from the results of the expert panel workshop.

The curve plots on the horizontal axis the probability that a disruption will occur in the next 10 years of at least x, for each value of x (in Mbpd, net of offsets). For example, the data point at 5 Mbpd and 42 per cent can be described as a 42 per cent chance that a disruption of one to six months duration of 5 Mbpd or larger will occur at least one time in the 10-year time frame 2016-2025. It is very likely that a disruption greater than 2 MMBD will occur (81 per cent). However, it is unlikely that disruptions greater than 15 Mbpd will occur (1 per cent). The curves allow one to identify easily the likelihood of disruption sizes within a range. For example, the probability of a disruption between 5-10 Mbpd is 34 per cent (probability of >5 is 42 per cent, probability of >10 is 8 per cent, difference is 42 minus 8 equals 34 per cent). The graph shows a larger weighting for the range between 2-8 Mbpd by the steep drop in the curve in that range. The distributions in Figure 56 combine the events in each of five regions alongside Table 6.

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Table 6 Assessment variables in the order they were assessed by a United States expert panel

Assessment Variable Variable Type Comparison of disruption probabilities by region

1 Middle East Conflict Underlying Event VERY LONG disruptions greater than 18 months

2 Saudi Internal Factors Internal Event

3 Other Persian Gulf Internal Factors Internal Event

4 Middle East Choke Points Choke Points

5 Saudi Shortfall Regional Shortfall

6 Saudi Duration Regional Duration

7 Saudi Offsets Excess Capacity

8 Other Persian Gulf Shortfall Regional Shortfall LONG disruptions of 6 to 18 months

9 Other Persian Gulf Duration Regional Duration

10 OPG Offsets Excess Capacity

11 Oil Price Scenarios Future Oil Production

12 Russia/West Conflict Underlying Event

13 Russia/Caspian Internal Factors Internal Event

14 Russia/Caspian Shortfall Regional Shortfall

15 Russia/Caspian Duration Regional Duration SHORT disruptions of 1 to 6 months

16 Africa Internal Factors Internal Event

17 Africa Shortfall Regional Shortfall

18 Africa Duration Regional Duration

19 Latin America Internal Factors Internal Event

20 Latin America Shortfall Regional Shortfall

21 Latin America Duration Regional Duration

Source: Beccue and Huntington (2016), Figure 17: Probability of a Disruption for All Durations, p.29

An initial comparison of the probability distributions in Figure 56 with the data on historical disruptions in Figure 50 suggests that the 2015 expert review process has generated materially higher probabilities than have been observed historically since 1951. Initial indications are that the probability of ‘black swan events’: very rare, large-magnitude, long-duration disruption events may have been under-estimated relative to what is implied by the historical data. However, considerable further in-depth research and analysis would be required to confirm (or reject) that hypothesis.

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Figure 56 An estimate of the probability distribution for disruption of global oil supply

2005 study 2015 study

Sources: Beccue and Huntington (2005), Figure 18a: Total Barrels Lost for a Given Disruption Size, p.25 and Beccue and Huntington (2016), Figure 17: Probability of a Disruption for All Durations, p.29

3.5. Analysis of differences and similarities in the oil market from 1975 to 2015

This section responds directly to the observation that oil markets have changed enormously since the first oil shock of 1973-74, by analyzing the differences and similarities in the oil market between 1975 and 2015. The sections below cover:

market information and data transparency

identification of similarities and differences using a side-by-side tabular comparison

highlights of what is different now

things we ‘knew’ for certain that turned out not to be the case

the paradox of spare oil production capacity

dilemmas faced by the swing producer

how the shale revolution is changing the responsiveness of oil supply to changes in price

the ability of the market mechanism to manage supply risks proactively

how shale oil interacts with spare capacity and other means of balancing the market, and

oil and the macro-economy: the causes and consequences of oil price shocks.

3.5.1. Market information and data transparency

Kristoufeka and Vosvrda (2013) analysed the market efficiency of 25 commodity futures across various groups—metals, energies, softs, grains and other agricultural commodities. They found that the most efficient of all the analysed commodities is heating oil, closely followed by WTI crude oil. The efficiency was also found to be characteristic for specific groups of commodities—energy commodities being the most efficient.

Both empirical evidence and theory indicate a strong relationship between information and efficiently functioning markets. Market transparency through the availability of data and information is an area that has changed enormously since the first oil shock of the 1970s. Before the first oil shock, data and information on oil supply and demand was opaque and difficult to obtain. Today, there is a wealth of data and information in the publicly domain. Freely available data sets range from the data published annually by BP in its Statistical Review of World Energy, to national statistical data, and the Joint Organizations Data Initiative databases. Additional data (and projections) are published by the IEA in its World Energy Outlook, and available via subscription databases. A number of research houses provide detailed data, including estimates of production costs at the level of individual fields, on a commercial subscription basis. International export and import trade data—including for crude oil and petroleum products—is compiled

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and published by the Observatory of Economic Complexity at Massachusetts Institute of Technology (MIT) in the United States, and by commercial providers.

After the formation of the IEA in 1974, and the United States EIA in 1977, oil data collection became more systematic. In 2001, APEC, Eurostat, the IEA, OLADE, OPEC and the UNSD launched the Joint Oil Data Exercise, which broadened within a year to cover 90 per cent of oil supply and demand and became the Joint Oil Data Initiative. Now the Joint Organizations Data Initiative, JODI publishes world databases for oil and gas.

Interestingly, the literature review of Kristoufeka and Vosvrda (2013) shows a pattern in which most earlier research from the 1970s, 1980s and 1990s found oil (and natural gas) markets to be inefficient, or rejected the efficiency hypothesis, while a number of later studies since 2000 show that oil markets are becoming more efficient over time, and that deregulation of the market has helped improve its efficiency. Efficiency is greater over longer time horizons, and most findings of continuing inefficiency tend to relate to short time horizons.54 Interestingly, this finding is consistent with Hayek’s contention, cited above, that only by far-reaching decentralisation in a market system with competition and freedom to set prices is it possible to make full use of knowledge and information.

3.5.2. Comparing the oil market in 2015 with 1975 to identify similarities and differences

Table 7 provides a side-by-side comparison of similarities and differences between 1975 and 2015, as relevant to the oil market. From the table it is obvious that many things in 2015 are the same or very similar to 1975, yet there are also significant differences. Some of the similarities will never change. The laws of physics are the strongest example, but not the only one. Oil fields are not created equal, so there will always be natural resource rent. Sovereign nations can always be expected to seek the largest possible share of the rent. The geology—oil in the ground—won’t change, but our knowledge of it is always changing. As the geological frontier advances, so does the technological frontier, and petroleum engineering advances.

Chapter 1 discussed the role of mutual inter-dependence in the oil market, rather than the notion of dependence or independence. The IEA noted the ‘globalisation of energy interdependence’ in 1993 (Scott, 1995b, p.223) and Fattouh and Van Der Linde (2011) noted this fundamental change on the twentieth anniversary of the IEF:

Perhaps the main achievement of the dialogue of the past twenty years is its success in increasing the awareness of the high degree of energy interdependence. Rather than treating it as a source of tension and conflict, the IEF has been calling upon both consumers and producers over the years to embrace interdependence “for its potential as a cohesive force underpinning healthy growth of the world economy, fair energy trade, and international cooperation”. Such statements are a far cry from the tense relations between oil producers and consumers that prevailed in the 1970s and 1980s and reflect how much has changed for the better in the relationship.55

The desire for constructive producer-consumer dialogue was actually present from the foundation of the IEA, but the initial hopes did not bear fruit until nearly 20 years later.56 The changes that can be seen clearly now—when the oil market of 2015 is contrasted with the oil market of 1975—came about incrementally as the cumulative result of a number of events over many years. Among the notable milestones were OPEC’s rejection in 1983 of production cuts (as described in section 3.1 on page 61), the formation of the International Energy Forum (IEF) in the 1990s to facilitate dialogue between oil producers and consumers (exporters and importers), and recently, the initiatives between Saudi Arabia and several oil importing countries, including India and South Korea, to locate oil storage capacity belonging to the exporter in the importing country.

Those changes occurred for a number of reasons, with at least one common factor: they were in the long-term interests of both the producer-exporter and the consumer-importer. This should not be surprising, given that it is consistent with the well-established economic theory of gains from trade. Without the availability of oil imports from the Middle East, import-dependent countries including in Asia, would need to turn to more expensive alternative sources of oil, or to more expensive fuels and technologies. Without the revenues from oil exports, the producing countries would need to turn to industries in which their comparative advantage is far smaller, and the profitability much lower.

Oil is a global market, and the effects of the changes of the last 40 years are experienced worldwide. The International Energy Forum (IEF)—which exists to pursue ‘energy security through dialogue’—is one example of the change in the landscape. The IEF has 72 members, which collectively account for almost 90

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per cent of the world’s oil and gas supply and demand. It brings together energy ministers from around the world every two years, and provides a forum for top-level industry executives preceding each Ministerial Meeting. This approach contrasts markedly with the atmosphere that prevailed in the 1970s, in which dialogue was limited to informal and ad hoc meetings between senior officials and executives, and where official dialogue was concentrated within OPEC and within the IEA.

The responses to the oil crises of the 1970s show the value of:

Allowing markets to work, prices to find their market clearing level, prices to signal the need for new supply (or not, as the case may be) and investment to respond to price signals

Increased information on supply and demand for market participants and policy makers

Development of financial markets to provide forward price signals and manage risk, and

Increased dialogue between producer-exporter nations and importer-consumer nations.

In contrast, attempts to manage prices, including government rationing (by some importing countries) and disrupting supply to customers (by OPEC), who turned to other sources of supply and energy were found not to work following the oil crises of the 1970s. Those policy approaches were eventually recognised as unsuccessful and abandoned. The market of today inherits the benefit of the lessons from those ultimately unsuccessful experiments.

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Table 7 Similarities and differences relevant to oil between 1975 and 2015

Things that are the same or similar in 2015 as in 1975 Things that are different in 2015 compared with 1975

Science, engineering and economics

Geology and the laws of physics

The basic principles of economics

Enormous technological advances in oil exploration, oil recovery rates, offshore production engineering, directional drilling methods, most recently with hydraulic fracturing

Policy and politics Affordability: energy prices and are still a political issue

Security of supply remains a major policy issue

Sustainability: environmental impacts are a major policy issue

‘Running out of oil’ replaced by ‘too much oil’ (stranded assets)

General views Popular negative views on the unsustainability of the oil industry Change from ‘exhaustible’ to ‘unburnable’ oil: atmospheric CO2 concentrations are now widely thought to be the limiting factor on oil demand in the long-run, not depletion of physical oil resources. This view has extended to fossil fuels in general, including coal and natural gas.

Resources and reserves Conventional oil reserves are the base of supply worldwide The shale ‘frontier’ has been cracked open at an industrial scale

The decline of US oil production was reversed by shale

The energy complex Oil is still the ‘senior energy source’

The cost of shipping oil is still a small fraction of its value (~1%)

The physical storage costs of oil are still low

Natural gas is a much more important fuel than in the 1970s

The financial cost of storage is low due to low interest rates

The demand-side transport sector and industry

The internal combustion engine remains dominant

The jet engine remains dominant in commercial aviation

Transport still needs oil: oil share of transport is >99%

Land, sea and air transport remain oil-dependent

Most non-transport can use energy other than oil

Some industries still need oil (e.g. open-cut mining, cropping)

Vehicle fleet efficiency is far higher than in the 1970s

Genuine alternatives to oil are now appearing (EVs, NGVs)

Taxes on oil and products Oil taxes in various forms are still high in most countries Moving from the production sharing to service contract era?

Economic considerations and economy-wide affordability

Oil natural resource rent globally remains very high The world can afford to spend more on oil in real dollars, as GWP has grown faster than oil demand.

Global monetary system Monetary tensions. Inflation is still an issue, … but:

Gold price spikes and surges (1970s & 2000s), … but:

The oil-gold price reversion pattern has continued

The United States is still the core of global banking and currency

low—not high—inflation is the challenge for central banks.

Interest rates were at historic highs and are now at historic lows

gold has retreated from its post-GFC highs, but not collapsed, and has not spiked to the same extent as the 1970s

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Things that are the same or similar in 2015 as in 1975 Things that are different in 2015 compared with 1975

International power US still ranks first in all five dimensions of international power: geostrategic and military, economic and financial, information and technology, political and diplomatic, cultural and linguistic

The USSR has collapsed, replaced by Russian Federation & CIS. China is clearly the new rising power, now second in economic size to the US, growing in geostrategic and military strength, advancing in information and technology, increasingly influential in international politics and diplomacy, and making a market in the cultural and linguistic spheres.

International security East Asia is again pivotal...

The US military remains dominant and guarantor of oil security

The Middle East is still politically unstable

The Middle East is again a pivotal region in international conflict

…but for different reasons this time.57 China, not the USSR (or Russia), is the main country ‘across the table’ from the US.

Non-state actors are a much larger risk. Saudi Arabia’s agreements with India and South Korea to store oil in the importing country suggests that governments of Middle East oil exporting countries now see their interests as aligned with oil importing countries over oil security concerns.

International institutions – OPEC

OPEC is still here and now more than 50 years old

Saudi Arabia clearly remains the leading member in OPEC

OPEC remains influential in the oil market

Some members (e.g. Indonesia) are no longer exporters

In the mid-1970s ‘OPEC enjoyed a near-monopoly on the external supply of crude oil to the industrialized world’58 while in 2015 OPEC’s influence is not as great

International institutions – IEA The IEA was formed in response to the events of the 1970s

The International Energy Treaty was entered into by industrialised economies from among OECD countries

Additional members have joined, including Australia (1979)

The IEA is pursuing deeper engagement with non-members, including China and India

The oil industry The oil industry represents a similar proportion of the economy

Exxon is still among largest US companies59

NOCs (and host country governments) were influential by 1975 and have remained so. IOCs role remained essential in most countries

The oil industry size is many times larger in 2015 than in 1975

Upstream oil projects are much larger and more challenging

Refinery scale is much larger today

IOCs role is being questioned in some countries

Oil production cost structures CapEx still dominates over OpEx in upstream oil production Higher OpEx sources, including Canadian oil sands and US tight oil is in the supply system, but CapEx still dominates.

The capital cycle is much shorter for onshore (unconventional) tight oil than for offshore and other conventional oil, and investment is less ‘lumpy.’

Marginal production costs are much higher today

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Things that are the same or similar in 2015 as in 1975 Things that are different in 2015 compared with 1975

Oil trade Geographic oil supply-demand imbalances remain similar

Straits of Hormuz are still a major geostrategic choke point

The Middle East is still dominant in oil supply

The US is still oil import-dependent (39 down to 35 per cent)

The EU is still oil import-dependent (95 down to 88 per cent)

Japan is still oil import-dependent (100 per cent: no change)

Big oil exporters are still highly oil revenue-dependent

US, Russia, Saudi Arabia remain the big three oil producers

OECD countries are gradually becoming less significant as their demand plateaus or declines and non-OECD demand grows

Demand is relentlessly shifting eastwards

China became oil import-dependent in 1993

In 1975, the US, Saudi Arabia and Russia between them accounted for over 48 per cent of world oil production. In 2015, their combined total production is larger, but only 38 per cent of world production.

Markets The oil price is still the most important price in the world

Oil is still priced and traded in US dollars

The oil market is deeper and more liquid

Financial markets are more sophisticated

Spare capacity Saudi Arabia still balances the oil market as swing producer60 A new source of supply (shale oil) has emerged which is less ‘lumpy’ and has shorter development lead-times than large, conventional oil developments, particularly remote, complex ultra-deepwater projects

Prices Prices in real dollars recently revisited the highs of the 1970s

Prices in real dollars have recently fallen, as in the 1980s

2000s oil prices echoed the 1970s…

Global oil expenditure did not reach the high 1970s GDP share

Prices have not (or not yet) reached the lows of the 1990s

Global oil expenditure has not (yet) fallen to 1990s GDP share

…but with a less steep shape

Fundamentals Large economies are the largest demand centres (US, EU, China, Japan, India)

The world’s biggest oil importer is a giant producer-consumer

The oil price is very sensitive to supply-demand imbalances

Mirror: 1970s (perceived) supply shock triggered a demand revolution; 2000s China demand surge triggered a supply revolution (shale)

Developed country demand decline Rise of China and Asia

China has overtaken the US as the world’s largest oil importer expected to overtake the entire EU in the foreseeable future

There has been no major negative supply shock since the 1970s

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3.5.3. What did we ‘know’ for certain that has turned out not to be the case?

The following quote is from a physical scientist, but it applies just as well to the social science of economics:

In science, there is an art to simplifying complex problems so that they can be meaningfully analyzed. If one oversimplifies, the analysis is meaningless. If one doesn’t simplify, then one often cannot proceed with the analysis.61

History shows that some views that guided our thinking about oil markets have later proved to be ill founded. For example, most of the economic literature from the 1970s to the 1990s assumed that oil price shocks could occur while all-else remained equal: ‘ceteris paribus’ in the economic jargon. It had also been thought that ‘negative supply shocks’ were the primary fundamental explanation of large, sudden oil price increases. It has since been shown that oil demand shocks collectively explain most major oil price fluctuations since 1973, with a central role played by flow demand shocks: i.e. actual underlying demand, not speculative demand to build inventory levels. In contrast, supply shocks play a relatively small role.

Better data, longer time series, more computing power, constructive debate and the accumulation of the body of research knowledge all enable models that avoid over-simplifying (or over-complicating) the problem to be proposed and tested.

Just as some formal economic models have been shown to have over-simplified the problem and led to erroneous conclusions, likewise, some of the informal ‘mental models,’ that non-economists and non-specialists carry in their minds to make sense of the market have been found to be misleading or in some cases just plain wrong. Such models tend to be based upon, or built around, statements that are believed to be factual, but are then contradicted by events. Some notable examples for oil include the following:

1. ‘The world would soon run out of oil.’ This view was widely held in the 1970s and is discussed in section 4.2.2 on page 118.

2. ‘Saudi Arabia will always reduce production to support the oil price.’ Although actually not supported by observed behaviour as recently as the mid-1990s, this view seems to have been widely held until the recent oil price collapse.

Examples may be found of other strong views, which many consider to be established strongly by consensus, while others consider controversial, but which are open to being confirmed (or contradicted) by future events. Two notable examples include the following:

3. ‘To limit carbon dioxide emissions and prevent dangerous climate change, we cannot produce and burn all of the earth’s economic oil reserves.’ This view is now widely accepted by governments and most large publicly listed corporations around the world.

4. ‘Saudi Arabia cannot control the oil market and OPEC is no longer relevant.’ This view has gained strong currency in some quarters following the 2014 collapse of the oil price.

It is notable that the third view in the list above is diametrically opposed to the first view and that the fourth is the opposite of the second view in the list. There is also a degree of tension between the second and fourth views, given that Saudi Arabia has the lowest costs of production and the strongest natural market position of any oil producing country. The last two statements are widely held at present, and may indeed be proved correct. But history has demonstrated that the first two statements were not correct. This is a salutary reminder of the danger of over-reliance on absolute statements that may be true under particular conditions, but fail to hold more generally. The real world is usually more complex and more nuanced than overly simple, absolute statements admit.

Economic frameworks can provide unifying and consistent perspectives and guidance applicable across a broader range of circumstances. The case of the build-up of pressure on oil supply in the late 1960s and early 1970s, as discussed in detail in the previous sections, provides an example. The nominal price of oil was regulated, and despite numerous step-wise increases, the real price was falling due to inflation. Accordingly, demand increased faster than supply expanded. Spare capacity in the United States was absorbed, and the United States became increasingly import-reliant, oil exporting countries in the Middle East gained economic leverage and the commercial influence of international oil companies declined. As a result, the Texas Railroad Commission was no longer able to regulate the price of oil and the Seven Sisters’

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system of posted prices could no longer be sustained. A consequence of this was that the system of price regulation that had contributed to the growing imbalance came to an end.

The high oil prices that followed had the usual dual effect familiar from conventional economic theory of reducing demand and increasing supply, and real prices returned to levels well below the peaks, but above their earlier levels. ‘In 1983, competition continued to mount rapidly in the oil market. The British sector of the North Sea, which had not even started producing until 1975, was now producing more than Algeria, Libya, and Nigeria combined, and still more North Sea oil would be coming on stream. To counter the competition, unofficial discounting and price-cutting became the norm among the OPEC countries,’ with the exception of Saudi Arabia.62

3.5.4. The paradox of spare oil production capacity

To retain spare capacity, the leading producer needs to invest to meet demand. The leading producer may not be able to do that, perhaps because of a lack of available geological resources to 'prove up' as new oil reserves, or perhaps due to a lack of already proven oil reserves to bring into production, or perhaps due to a lack of capital. If that is the case, and if consumers do not reduce demand via fuel switching and energy efficiency—which they will not if prices are not high enough to encourage them to do so—then the leading producer becomes reliant on other producers to invest to meet demand as the market grows. If other producers do not do that, either because they are unable to for similar reasons as the leading producer, or because they are unwilling to do so for other reasons, then one of two things must follow:

(a) the leading producer's spare capacity will be absorbed in meeting the growth; it will then no longer have spare capacity and will lose pricing power, or:

(b) the price will naturally rise as the leading producer continues to reserve its spare capacity.

Scenario (a) is what eventually happened in the case of the United States in the early 1970s. The process reached its dramatic conclusion in 1973.

However, the process had actually been set in train much earlier—the United States was already a net oil importer since the late 1940s (as Figure 12 on page 18 shows). United States companies investing internationally, especially in Saudi Arabia, had slowed the natural erosion of pricing power that would naturally follow. United States investment in Saudi Arabia began in 1933, when the first concession was granted to Standard Oil of California (SOCAL) and delivered its first fruits in 1938, with first commercial production. Exports of oil from Saudi Arabia enabled the United States to continue to carry flexible spare production capacity, particularly in Texas. The control of Saudi production by the Seven Sisters under concession arrangements (and similar control by international oil companies of other concessionaire production around the world through the 1950s and 1960s) made this situation possible.

The replacement of the concession arrangements with production sharing agreements in most oil exporting countries during the 1960s and 1970s, the nationalisation of the oil industry throughout the Middle East and in numerous other countries, and the establishment of OPEC in 1960, all eventually removed the ability of United States interests to manage the world oil market. That had been achieved by a system involving the Seven Sisters' posted prices and the regulation of production domestically by the Texas Railroad Commission, along with similar regulatory bodies in other United States states.

It is clear in hindsight that oil prices were held unsustainably low throughout the 1960s and 1970s. Certainly prices were too low to create sufficient incentive for new investment to meet the rate of demand growth, and too low to discourage demand from growing at a rate that the industry could match. The problems that were being created by unsustainably low oil prices were masked by the gradual absorption of United States spare capacity to meet demand, until by March 1971 there was finally no spare capacity left.

Saudi Arabia and its OPEC partners then found themselves controlling the spare capacity, but without the benefit of several decades of experience in managing one of the most finely-balanced and economically essential markets in the world. It also happened to be a time of elevated tension and conflict in the Middle East.

The consequence of scenario (a) is that when prices eventually rise, as they must, they will do so very steeply indeed. Therefore someone will eventually invest in new production and then prices will fall. Both the project cycle from exploration to production and the empirical price data tell us that the time lag to correct such an imbalance has historically been about ten years. In scenario (b), if there is a well-

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functioning market, then the price should rise sooner and more gradually than in scenario (a), providing a better signal for investment.

Scenario (b) is more or less what happened after 2000, as China's oil import growth began to accelerate. And even though the oil price rose to very high levels, the industry was surprised by the sheer rate and scale of demand growth and struggled to keep pace. Saudi spare capacity was being absorbed at that time, so it also contains some aspects of scenario (a), but nonetheless the period is a good (but not perfect example) of scenario (b).

A very similar pattern occurred in other commodity markets at the same time. Most of the major producers had previously not believed that China's demand for imports could grow quite so rapidly. (Incidentally, the experience from that time underscores the importance of not only the open and transparent exchange of data, but also of regular, frank, producer-consumer dialogues with high level support, and involving government policy-makers and company decision-makers exchanging analysis and views based on that data. The OPEC-IEA-IEF meetings are a good example).

Managing the spare capacity that is needed to balance the oil market in real time is an exorbitant privilege, a heavy burden of responsibility, needs deep understanding and insight supported by detailed and accurate data and high quality analysis, and is a serious challenge requiring good judgment and wisdom.

OPEC is often criticised, and is continually second-guessed, but viewed from the perspective of the decision-makers, it is fair to ask: how many others could do a better job of balancing the world oil market?

3.5.5. Dilemmas faced by the swing producer

In any tightening market, the problem for a producer managing the spare capacity is to distinguish temporary upswings in demand from acceleration in the underlying rate of year-on-year growth. That is easy to do after the fact, but very difficult to do in real time. Myriad disruptions in production supply around the world need to be accounted for, including forecasts of their duration and the magnitudes and durations of future disruptions, along with storage inventory levels and the behaviour of those holding storage. Once again, high level, high quality, regular producer-consumer dialogues are of utmost importance.

On the other hand, a loosening market presents the market balancer with the problem of distinguishing between a temporary widening of the gap between global production capacity and global demand, and a fundamental change in the supply-demand balance. This also presents a dilemma. Should production be curtailed to support the price? Or should market share be preserved?

If production is curtailed, and the price is sustained at a more or less constant level, then revenue will fall in proportion to the curtailment. That scenario reduces the return on spare capacity. In the limit, production is curtailed to zero, the producer has maximum spare capacity and no commodity market share, and no revenue.

The producer holding the spare capacity will face a survival problem long before that limit is reached. As soon as the trend points towards the limit, it is clear that a fundamental change in the supply-demand balance is underway, not a temporary widening of the gap between global production capacity and global demand.

When that happens, there is no longer a dilemma, the leading producer is compelled to act by increasing production to defend its market share, in an attempt to stop and reverse the fundamental change occurring in the supply-demand balance.

That is exactly the situation that Saudi Arabia found itself in in late 2014. The growth of United States light tight oil production resulted from disruptive technology introducing new infra-marginal supply, which changed the balance between supply and demand, and especially between exports and imports.

This highlights another important distinction between the United States exhausting its spare capacity in 1971 when the TRC ordered full production, and Saudi Arabia 'opening the taps' in 2014. The United States maximised its production, exhausting its spare capacity in a tight market, because it was the world's largest importer. In contrast, Saudi Arabia maximised its production in a loose market, to retain its position as a leading exporter. That happened eight years after Saudi Arabia was very close to maximising its production in a tight market near the height of the boom in 2008.

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Nevertheless, the changes in the oil market—including the advent of shale oil in the United States—prompts the question: Is the oil market becoming a ‘normal’ competitive commodity market, just like any other commodity market?

The question as to whether the oil market is ‘special’ or ‘just another market’ needs to take into account many considerations, and is addressed in Chapter 4. It is nevertheless useful to focus specifically on how shale oil interacts with spare capacity and other means of balancing the market. Section 3.5.8 addresses that topic. Before that, section 3.5.6 discusses how the shale revolution is changing the responsiveness of oil supply to changes in price and section 3.5.7 discusses the ability of the market mechanism to manage supply risks proactively.

3.5.6. The shale revolution is changing the responsiveness of oil supply to changes in price

The emergence of unconventional oil provides a textbook example of the price-responsiveness of supply. As it happened, it was high natural gas prices in North America that provided the catalyst for the technological marriage between horizontal drilling and hydro-fracking for the commercial production of shale gas. After the surge of supply had the usual effect of collapsing prices, the revolution moved to ‘wet gas’ containing natural gas liquids, which collapsed the prices for ethane, propane and butane. Finally, attention of the industry turned to targeting light tight oil, made attractive by oil prices remaining persistently high by historical standards. The degree of technical success achieved was sufficient to begin to displace (indirectly) OPEC production, and particularly Saudi production in the world oil market. Saudi Arabia’s ensuing defence of its export market share, combined with the price inelasticity of most other oil supply, precipitated an oil price collapse.

Several important changes have opened up as a result of the shale revolution. One change is that onshore light tight oil can be developed in much smaller increments of supply than can conventional oil. Another change is that the project development time for shale oil is shorter than for conventional oil projects by at least an order of magnitude: considerably less than a year, in contrast with a decade or more for challenging offshore ‘mega projects’ in remote locations. This may mean that the new infra-marginal unconventional oil makes overall supply more price-elastic than was the case before.

Another major change is that expectations about the shape of the long-run oil supply curve have changed, as reflected in the shape of the forward price curve. The forward price curve is a key part of the market mechanism in managing supply risks proactively, as described in the next section.

3.5.7. The ability of the market mechanism to manage supply risks proactively

On any given day, prices for futures contracts trace out a trajectory called the ‘forward curve’ or the ‘forward price curve,’ as shown in Figure 23 earlier in this paper. When the spot price moves, the front end of the forward curve moves as well. To illustrate this, Figure 57 shows daily spot prices for Brent crude oil from 1990 to 2016, and a selection of forward price curves.

At the height of the price surge in the middle of 2008, the front end of the forward curve was in contango for the first few months, while the back end of the forward curve was in backwardation. As the price fell to the bottom of the trough in December, the curve moved into steep contango.

The chart shows the interaction between the market’s view of short-run (spot) prices and longer-run (forward) prices throughout one of the most dramatic step changes in the history of oil prices: from the peak of $144/bbl on 3 July 2008 before the Global Financial Crisis to the bottom below $34/bbl on 26 December 2008. By the beginning of February 2011, prices had again surpassed $100/bbl and remained above that level until 4 September 2014, trading between $100 and $120 with an average of about $110. Interestingly, prices from 2011 to 2014 were about in the middle of the envelope defined by the forward curve at the top of the market at the end of June 2008 and the forward curve at the bottom of the market at the end of December 2008. In other words, the market’s expectation before the shale oil revolution was of medium- to long-run prices around $110/bbl plus or minus $30. In late 2016, the market’s expectation is of prices around $60 (the forward curve currently terminates in the first quarter of 2023): $20 lower than the expectation in the depths of the GFC.

Nevertheless, the market at the time of writing is in contango, signaling an expectation of rising prices and encouraging the buildup of physical stocks, which is exactly the behaviour currently observed.

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Figure 57 History of oil prices and selected forward curves, 1990-2016

Sources: Author’s calculations using price data from the EIA, the BP Statistical Review of World Energy, 2016 and online market data from the Wall Street Journal, available by subscription at quotes.wsj.com/futures accessed from June to December 2008

3.5.8. How shale oil interacts with spare capacity and other means of balancing the market

Figure 58 compares five major supply side contributors to balancing the crude oil market:

investment in new conventional oil supply

investment in new unconventional (shale) oil supply

management of spare capacity to increases or decrease Saudi Arabia’s production

movement of oil into or out of storage through commercial inventory management, and

release of emergency stocks made available for drawdown.

The first three are sources of supply, the last two are forms of storage, so net to zero over time.

The vertical scale of the shapes in Figure 58 is in approximate proportion to the contribution of each category. Commercial inventory will typically manage fluctuations of half a million barrels per day in either direction. Saudi Arabia’s spare capacity will flex up and down by about 1 Mbpd in either direction through a range of about 2 Mbpd. The United States’ Strategic Petroleum Reserve (SPR) can draw down in its initial stage by more than 4 Mbpd, to which can be added the emergency reserves of other IEA countries, as well as some non-IEA countries, including China, which is advancing in the establishment of its own SPR. United States shale oil has added about 5 Mbpd of supply over five years. World conventional supply grew by a little more than twice that amount in the 10 years before the shale revolution.

The combination of responsiveness, lead time, ramp-up, capacity deliverability and sustainability differs between the categories of supply balancing: no two are alike. The characteristics of shale oil mean that it may be able to play a unique and crucial role in the medium-term time-frame to balance supply and demand, by responding to price signals in a way that no other supply-side assets can. That capability has the potential to relieve some of the pressure on Saudi spare capacity in balancing the market over time frames of one to five years, potentially minimising the problem of the ‘the paradox of spare oil production capacity’ described in section 3.5.4. However, there will still be a role for flexible spare production capacity, because the fastest lead-time for new shale production is about six months, and twelve months is probably more typical. The chart illustrates the cumulative effect over a five-year period of production from many individually small shale wells.

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Figure 58 Comparison of supply side contributors to oil market balancing

Sources: Author’s chart, with examples broadly based on data for the period 2011 to 2015

Figure 59 shows the correlations between the number of active horizontal drilling rigs in North America (the time series data in Figure 46) and the WTI crude oil price with the time series lagged by 17 weeks (119 days), through the phases of expansion and contraction of the United States light tight oil revolution from 1991 to September 2016.

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Figure 59 Correlations between US active horizontal drilling rig count and lagged WTI crude oil price

Sources: Baker Hughes (2016), United States EIA (2016), author’s analysis and chart

Several phases of the horizontal drilling and hydraulic fracturing revolution are identifiable in Figure 59: (1) experimentation, (2) persistence through falling prices, (3) a price spike, (4) the GFC collapse, (5) the post-GFC boom or LTO revolution, (6) the retracement and then (7) the beginnings of a recovery. The details are also shown in Table 8.

About 200 horizontal rigs were added through the experimentation phase up to late 2006. By that time, active horizontal rigs were still in the minority in North America: 302, compared with 380 directional and 1015 vertical rigs. Furthermore, 1395 of the active rigs were targeting gas and only 297 were targeting oil (plus 5 ‘miscellaneous’). United States natural gas prices spiked in late 2005 to about $15 /MMBtu and gas drove the early stages of the North American horizontal drilling and hydro-fracking shale revolution. During the 15-years from 1991 to 2006, 42 horizontal rigs were added for every $10 per barrel increase in the WTI price, with co-efficient of determination (R-squared) of 0.90. In 2006, natural gas prices had come down from their peak, but as oil prices fell during the second half of 2006 natural gas prices and expectations remaining strong enough to see about 20 horizontal rigs added for every $10 fall in the WTI price.

Oil prices turned around the beginning of 2007 and began their steep rise towards the pre-GFC peak. United States Natural gas prices turned in mid-2007 and began a parallel rise, although natural gas only reached $13 /MMBtu. From May 2007 to the end of October 2008, 33 horizontal rigs were added for each $10 bbl increase in the WTI price (R2: 0.92), taking the horizontal rig count from 372 to 650 in just over 16 months. Natural gas was still driving the shale industry at that time, but WTI crude oil and Henry Hub natural gas prices were again strongly correlated.

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Table 8 Phases in the United States light tight oil industry (horizontal drilling and shale oil fracking)

Phase Dates Rigs WTI Price Response Correln Actual Lag

count (note a)

US$ /bbl Rigs per $10 price change

(note b) R2

(note c)

days (weeks)

Start of data series 4 Jan 1991… 100 25 (30) — — —

1. Experimentation …24 Nov 2006 302 60 (77) +42 0.90 133 (19)

2. Persistence …11 May 2007 372 62 (52) +20 (b) 0.58 112 (16)

Shale GAS boom:

3. Price spike …31 Oct 2008 650 68 (142) +33 0.92 119 (17)

4. GFC collapse …22 May 2009 375 61 (33) –26 0.97 154 (22)

Shale OIL boom:

5. Boom …24 Oct 2014 1 355 81 (107) +145 0.79 133 (19)

6. Retracement …27 May 2016 314 49 (29) –148 0.93 105 (15)

New era:

7. Recovery ...23 Sep 2016 402 43 +44 0.88 —

Source: author’s analysis. Notes: (a) The prices in brackets are the price at the turning point (price peak or price bottom) prior to the rig count turning point. (b) The lag used for all of the correlations is the WTI price 17 weeks earlier. (c) The actual lags from each price turning point to the subsequent rig turning point varied from 15 to 22 weeks.

As oil and natural gas prices collapsed during the GFC, 26 horizontal rigs were removed for each $10 /bbl decrease in the WTI price (R2: 0.97). The number of horizontal rigs fell from 650 to 375 in just over six months. Despite some volatility, North American natural gas prices have not recovered following the GFC. As the oil price rebounded, horizontal drilling rigs were deployed and targeted at light tight oil in what became a boom on a larger scale than the shale gas boom (Figure 45 and Figure 46). Horizontal rigs were deployed at the rate of 145 additional rigs for every $10 /bbl increase in the WTI price (R2: 0.79). Then, about 19 weeks after the WTI price began to collapse, horizontal rigs were removed at the rate of 148 for every $10 bbl fall in the WTI price. The horizontal rig count bottomed at 314 in May 2016. The recovery process began 15 weeks after the oil price bottomed at below $30 /bbl. From May to September, horizontal rigs were added at the rate of 44 for every $10 /bbl increase in the WTI price (R2: 0.79)—a slower rate than during the post-GFC boom, but similar to the price responsiveness during the experimentation phase and the pre-GFC price spike.

The North American shale gas and light tight oil industry is a pioneer industry within an old industry. It displays many of the characteristics of earlier boom industries, from gold and land rushes to railways to bicycle and automobile and computer manufacturing, and indeed to the early decades of the conventional oil industry. After the early boom, the phase of bankruptcies, acquisitions and industry consolidation has begun. The next growth phase is likely to see less dramatic rates of growth. Shale oil is not a new ‘swing producer’ because it cannot swing production up and down on a monthly to quarterly time frame, and it does not meet the accepted definition of spare capacity. However, it is an important new infra-marginal supply, uniquely able to respond with small increments of capacity and to ‘back-off’ and allow production to decline naturally as prices fall.

3.5.9. Oil and the macro-economy: the causes and consequences of oil price shocks

The paper Oil Price Shocks: Causes and Consequences (Kilian, 2014) is a valuable reference for any reader interested in the relationship between the oil market and the macro-economy:

…whereas traditionally the real price of oil was thought to be determined primarily by political events in the Middle East that were outside of the confines of macroeconomic models and could simply be taken as given when conducting policy analysis, it is now widely accepted that the real price of oil is determined endogenously in global markets much like the price of other global commodities.

Kilian’s paper shows that the causes of oil shocks are different from what was thought previously, and that the economic consequences of oil price shocks are not as severe as was previously thought. Furthermore, a

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deep understanding the economic consequences of oil shocks, including the direct effects on real GDP, the direct effects on inflation, and the indirect effects on GDP requires a model that properly represents the transmission of oil price shocks through the supply channel and through the demand channel.

Because the real price of oil is endogenous with respect to economic fundamentals and because oil price shocks do not occur ceteris paribus, it is necessary to account for the deeper structural shocks underlying oil price shocks when studying their transmission to a given domestic economy. Kilian (2014) has come to the view that the approach of using parsimonious structural vector auto-regressive (VAR) models of the global oil market based on minimal identifying assumptions has probably been advanced as far as currently possible.

For macroeconomic policy analysis, an even richer shock structure is required than is the case for VAR models, which necessitates the development of truly global dynamic stochastic general equilibrium (DSGE) models in which the oil market is one of many markets with endogenously determined oil prices. A DSGE framework allows users to differentiate between, for example, fiscal and monetary policy shocks as well as productivity and oil intensity shocks while at the same time differentiating shocks by geographic origin.

In other words, oil and the global macro economy are deeply interwoven, as are markets and economy-energy-environment (‘3E’) policy settings. This was recognised as early as 1993 by the IEA Ministers, whose Communiqué that year stated that they ‘believe that global economic development, energy security and environmental protection will be enhanced if all nations of the world subscribe to the goals which the IEA countries share.’ These ‘Three Es’ of energy policy provide the base for the IEA Shared Goals (Scott, 1995b, p.224).

The challenges for DSGE modelling include: (i) compiling the international data required to build reliable global DSGE models disaggregated by geographic region; (ii) modeling the interaction of the financial sector and the real sector, especially at the global level; and (iii) introducing expectations-driven shifts in inventory demand into DSGE models.

In summary, we have a significantly more robust understanding of the relationships between the oil market and the wider macro-economy than was the case at the turn of the millennium, and that understanding has fundamentally changed the earlier accepted view of the causes and consequences of the 1970s oil shocks. We also have a better idea of what we don’t know, and the challenges in the work required to answer the outstanding questions that have been identified.

3.6. Oil market influences and ‘surprises’

The previous sections describe a large number of factors that influence the oil market. Those factors interact in complex ways. How significant are each of the complex set of influences on the market? This section describes in general terms the relative influence of those factors on the oil market.

3.6.1. Geology and geography

Geology and geography have a fundamental long-term influence on the oil market. All else being equal, the characteristics of the rocks in which oil is trapped and the location of those rocks on the earth, have a profound influence on the cost of exploring for and recovering that oil. The depth and shape of the oil deposit determines the length and shape of the wells drilled into the formation. The porosity of the rock strongly influences the quantity of oil in the rock, and the permeability of the rock strongly influences the ability of the oil to flow under pressure to the well and to the surface. The geographic location of an oil deposit also influences exploration and production costs. The remoteness of the location, the distance from shore and the depth of water for offshore operations, the climatic and weather conditions, all have cost implications. While geology and geography are ‘given’ (they cannot be changed by policy), resources occurring in difficult geological conditions and resources that are geographically remote from markets can become economic due to innovation and technological advancement.

3.6.2. Technology

Technology is the major exception to the qualifier: ‘all else being equal’ because technology is continually improving. Technological improvements in both exploration and production have the two-fold effect of opening up previously inaccessible resources and of reducing the cost of producing oil from a deposit with a

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given set of characteristics. This effect expands the base of resources with economic potential and enlarging the size of commercially recoverable reserves. Taken together, technology ‘stretches out’ and ‘pushes down’ the cost curve. One of the effects of technology has been to improve recovery rates. The average oil recovery factor worldwide is only between 20 and 40 per cent.63 Enhanced Oil Recovery (EOR) technology contributes to increases in the rate of oil recovery.

Technology provided the keys that enabled United States ‘unconventional’ shale beds containing light tight oil to be unlocked on an industrial scale in recent years. As a result, the most commercially attractive onshore conventional oil can now be produced at a lower cost than the highest cost offshore conventional oil in companies’ long-term development plans. Less than a decade ago, most industry players did not think such a situation would be possible.

The evolution of technology in the supply of oil expands the frontier of potentially economic resources and of commercial reserves. The evolution of technology on the demand side improves energy efficiency, thereby ‘stretching out’ available oil reserves.

3.6.3. Probabilities and risk

Probabilities play a key role at each stage of the industry, from resources to prospects to discoveries to proven, probable and possible reserves to investment in capacity, to production and supply of oil to the market. Exploration is a game of probabilities. Estimates of production involve probabilities. The single line path of expected future prices has a probability distribution above and below. Complex risk management is a major and inherent theme for the oil industry throughout the supply chain.

3.6.4. Economics

Economics has a major influence on the oil market. At the macro level, a larger economy producing higher levels of GDP per capita in real terms, and with a greater stock of investable capital, is able to support a larger, more capital-intensive and more technologically advanced oil industry. Greater investment in exploration and production enlarges the stock of proven reserves. This is very important in an industry characterised by proportionately low on-going production operating costs, but high up-front fixed capital costs combined with high levels of technical and non-technical risks.

While technology drives costs down for any given type of oil deposit, the long-run marginal cost of production required to meet global demand is generally increasing. During phases of tightening supply and demand, prices need to be sustained at levels that are high enough to justify capital investment in exploration and production. During phases when the market is loose, prices can be driven down to or below the short-run marginal costs of the most exposed producers.

Due to the large difference between the costs of the lowest cost producers and the highest cost producers, the economic attractiveness of oil, and the costs of alternatives, there is substantial natural resource rent in the oil industry. Resource rent—arising from the difference between market prices and the cost of production—is divided between host country governments and their national oil companies and international oil companies, typically via production sharing agreements and royalty terms, and governments in oil importing countries via various taxes.

3.6.5. Alternative energy sources

Alternatives to oil include electricity, natural gas, coal, nuclear power, hydropower and renewable energy sources. Electricity is an energy carrier, not a primary source. Electricity faces challenges in displacing oil in the transport sector, but battery-electric vehicles are making some early inroads in some countries. Most electricity is generated from coal, gas and uranium; the opportunities for those fuels to displace oil in the power sector has already been taken up. (Exceptions remain, including in countries in the Middle East that have continued to use oil for power generation, and in developing countries with poorly developed grid supply where households and businesses fall back on expensive diesel-fired self-generation to ensure reliable supply). In most markets where piped natural gas is available it has tended to displace oil, not only in power generation, but also in heating and industrial applications for example. Natural gas is no longer oil's poor cousin. Coal is under pressure for environmental reasons, but coal reserves are vast, low cost and secure, and coal remains the dominant fuel in Asia for low-cost base-load power. China is looking to increase the use of coal as a feedstock for coal-to-oil, coal-to-liquids and coal-to-gas projects. Nuclear power surged in the 1970s, particularly in the United States, France, and Japan, followed by a slump and

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something of a renaissance in China and elsewhere in Asia in the new century. Hydropower is a well-established energy resource that tends to be developed on rationale not necessarily directly linked to oil prices. Other renewable energy sources including wind and solar power benefit from sustainability policies, continue to require a degree of direct or indirect subsidy, and tend to displace energy sources other than oil in the power sector.

3.6.6. Commerce and governance

Governments play a very important role in the oil market, particularly in oil-exporting countries. Government policies—particularly those related to energy and the environment—are also a factor. In many countries, Governments are represented through their National Oil Companies (NOCs). Governments seek to capture as much of the natural resource rent as possible in their national endowments of hydrocarbons, without destroying the incentive for investment in exploration and production by the International Oil Companies (IOCs).

The fiscal terms in each country determine the division of the rent between the host government and the companies. Production Sharing Agreements (PSAs) are the most common form of fiscal arrangements, having displaced the earlier concession model in the 1960s and 1970s. Historically, the cost of production has accounted for one-third to one-quarter of world expenditure on oil at international market prices and natural resource rent has accounted for the remaining two-thirds to three-quarters of this expenditure (see Figure 67 below).

The process by which host governments seek to secure the largest possible share of the natural resource rent is usually described as ‘resource nationalism.’ Stevens (2008) describes how ‘resource nationalism’ is a cyclical phenomenon driven by exogenous and endogenous factors. Among the factors endogenous to oil are: the level of oil prices at the time the agreements are signed, the degree of competition for acreage when the agreements are signed, the sophistication of the negotiators and the current level of oil prices. Another key endogenous factor is how far the owner of the reserves needs the private companies to provide capital, technology and markets. Stevens notes that high prices mean no shortage of capital and an easy ability to buy the technology, but as the geology gets more complex and difficult, there is a need for access to more sophisticated technology.

3.6.7. Banking, finance and the monetary system

Because oil exploration and production is very capital-intensive, the banking system plays an important role in directing finance to the industry through the debt markets. The monetary system plays an important role through the prevailing interest rate. Equity markets play an important role in the provision of equity capital. The IOCs are some of the largest publicly-listed companies in the world by market capitalisation, although as Table 3 on page 38 suggests, many of the NOCs are even larger.

Although oil is priced and internationally traded in US dollars, consumers purchase the final products in their domestic currency. Therefore, foreign exchange rates also have an influence on the oil market. Imports and exports of oil make up a substantial portion of the trade balance of many countries, particularly the major oil exporting countries and the rapidly growing emerging economies on the import side of the market. The latest available data from 2014 indicate the extent of the contribution of oil as a share of export revenues by a number of major oil exporting countries:64

South Sudan 99.8%

Iraq 99%

Angola 96%

Chad 95%

Venezuela 93%

Azerbaijan 92%

Kuwait 86%

Saudi Arabia 82%

Libya 82%

Gabon 82%

Nigeria 78%

Iran 74%

Equatorial Guinea 69%

Oman 68%

Sudan 68%

Yemen 66%

Republic of Congo 64%

Kazakhstan 63%

United Arab Emirates 58%

Algeria 56%

Russia 54%

Therefore, it is not surprising that movements in the price of oil also have an effect on exchange rates (and vice-versa), as well as on other indicators of the macroeconomic condition of economies. The collapse in oil prices in late 2014 has had a significant effect on the terms of trade of many of the countries listed above, and in most cases is reflected in the market exchange rate of their currencies. Interactions between the oil

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market and the financial markets, and between the oil market and the international monetary system are discussed further in section 3.7.2 on page 107.

3.6.8. National and international institutions

Most of the institutions listed in section 2.2.15 on page 59 are on the oil importing side of the market: the IEA among OECD countries, the DoE and EIA in the United States, APEC in Asia Pacific, the IEEJ in Japan, and ERI, the NEA and NDRC in China. Apart from the role of the IEA in managing the emergency reserves system, the ability of most of those organisations to influence the oil market is indirect. It involves the gathering, analysis and publication of data, and advice to policy-makers. The IEF provides a forum for oil exporters and importers to meet and build mutual understanding, which is believed to have a positive effect on the market. The World Energy Council brings together companies and countries from around the world every three years and publishes data and analysis on energy generally that complements that available from other organisations.

Yet, of all the international institutions relevant to oil, it is OPEC that has undoubtedly had the greatest influence historically on the oil market. OPEC has managed the balance of supply and demand and its decisions, actions and words have influenced prices and policies around the world. At the time of writing OPEC has found itself unable to sustain prices and all of its members are suffering the economic and political effects of a sudden large fall in oil prices. OPEC’s leading member country, Saudi Arabia, has changed from defending the price level to defending its market share. There are echoes of the 1980s when OPEC also found itself unable to sustain prices.

Whether OPEC is able to recover its influence remains to be seen. The outcome will depend to a large extent on the sustainability of United States light tight oil production at lower price levels than prevailed during the shale revolution, on the future trajectory of United States interest rates and on equity and debt investment risk ratings for the oil sector, and on whether a period of under-investment or an resumption of higher demand growth, or both, leads to a tightening of the market. For the time being, OPEC’s ability to influence the oil market has been greatly diminished.

3.7. Reconsidering ‘popular wisdoms’ about the oil market

This section revisits a number of popular wisdoms related to the oil market:

The 1970s oil shocks were caused by supply interruptions. Comparing the ‘supply shocks’ of the 1970s with the ‘demand shock’ of the 2000s reveals a number of striking parallels, and well as informative differences, and point to a deep revision of the popular wisdom of cause-and-effect.

Oil prices were extremely high in 2008 and from 2011 to 2014. This popular view is correct when the oil price is viewed in any paper currency. However, comparing oil prices relative to gold prices across 125 years indicates that recent prices were not particularly high in historical terms, and that 2015 oil price levels are very similar to other major historical lows.

Turning points in the oil market are random and entirely unpredictable. The long historical data of oil and gold prices reveals a distinct price cycle, closely analogous to the ‘energy evolution cycle.’ While the duration of the cycles differs, the turning points coincide perfectly with distinct eras defined by pricing regimes, as identified in the literature.

The oil market needs emergency crude oil reserves equal to 25 per cent of annual imports. This view is the basis of the International Energy Partnership that constitutes the IEA, and has also been adopted as Chinese government policy. Comparison with the banking system is interesting: under the central banking system, banks today have core capital buffers (equity) of 5 to 10 per cent, whereas British and American banks in the late 19th century retained equity buffers of 20 to 25 per cent of assets in the form of cash and government bonds.

3.7.1. Comparing the ‘supply shocks’ of the 1970s and the ‘demand shock’ of the 2000s

The 1970s saw an oil supply shock, reflected in a near-vertical price increase, followed by a major demand-side response. It is a commonly held view that the oil shocks of the 1970s were simply caused by the Arab-Israeli Yom Kippur War and the Arab Oil embargo in 1973; and the Iranian revolution in 1978 and the outbreak of the Iran-Iraq War in 1980. As alluded to in previous sections, economic perspectives on the

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1970s oil shocks contrast with this ‘conventional wisdom’ and reveal surprising parallels with the 2000s. The 2000s saw an oil demand surge, accompanied by a large, sustained and relatively steady price increase, followed by a widely unexpected supply-side response from tight oil (and shale gas) in the United States. Table 9 provides a side-by-side overview of the energy evolution cycles of the 1970s and 2000s.

Table 9 Overview of the timing of the energy evolution cycle, 1970s and 2000s

First oil shock Second oil shock China Boom-GFC Quantitative Easing

Growth and dependency

Pre-1970 1976-77 2002-05 2010-11

Pressure build-up

1971-73 1978 2006-08 2012-13

Break-point

1973-74 price shock

1979-80 price shock

2008 price peak

2014 end of rebound

Rebalancing

1975 pause

1981-2001 inflation erosion

2009 price crash

2015-… price collapse…

Source: author’s analysis

The parallels between the 1970s oil shocks and the recent ‘double peak’ in oil prices are striking. The ‘energy evolution cycle’ of growth and dependency, leading to pressure build-up until a break-point is reached, followed by rebalancing, are clear in all cases.

A ‘double crisis’ is also evident in both the 1970s and in the recent example. It is perhaps human nature to need a repeat of the signal before the message from the market sinks in. Or perhaps it is simply the case that, because the supply-side and demand-side responses take time to implement, a second crisis (or high price event) tends to occur before the responses can truly rebalance the market.

In any case, the overview in Table 9 and the additional qualitative analysis in Table 10 lends further support and contextual material to the conclusion that it is misleading to view the 1970s oil shocks as primarily or even purely ‘supply side events’ in the Middle East, while viewing the 2000s high oil price events as primarily or even purely ‘demand side events’ in China. Both the demand-side and the supply-side played a role in both cases.

Kilian (2014, p.138) goes further, based on his own research, research with colleagues, and other studies, in stating:

These and other studies provide overwhelming evidence that oil demand shocks collectively explain most major oil price fluctuations since 1973, with a central role played by flow demand shocks. Only for the 1990 episode is there evidence that flow supply shocks played a non-negligible role (Kilian & Murphy 2014). Whereas the idea that flow demand shocks can explain major oil price fluctuations was met with great skepticism when it was first proposed by Barsky & Kilian (2002), this view is the conventional view today.

It is notable that ‘the idea that flow demand shocks can explain major oil price fluctuations’ was first proposed before the most recent aggregate demand shock in China’s ‘Golden Decade’ of growth. The conclusion that ‘oil demand shocks collectively explain most major oil price fluctuations since 1973’ is very significant, reinforced by the conclusion that fundamental ‘flow demand’—in contrast with speculative ‘inventory demand’—played the central role. While this ‘is the conventional view today’ among economists, it may not have filtered through to all policy-makers or the general public.

Interestingly, the official history of the IEA (Scott, 1995b, p.223) contains this prescient observation, followed by a risk warning, and a policy recommendation:

The rapid growth in oil consumption and the increased dependence of a growing number of industrial countries upon imported oil are reminiscent of the conditions which led to the 1973-1974 oil crisis carrying again an unacceptable vulnerability to oil supply disruptions. But such vulnerability may be reduced or eliminated if the necessary energy policy measures are adopted and implemented on a timely basis.

The fact that the oil market proved resilient to supply disruptions emphasises the effectiveness of the market and the policies that were in place throughout the two decades since 1995. The focus of the IEA in 1993 was on ‘Freer Markets and IEA Shared Goals.’

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The 1970s witnessed rapid American-led growth in demand for oil and oil imports combined with artificially low oil prices creating problems for supply and investment. The 2000s were driven by Chinese-led growth in demand for oil and oil imports following an era of prolonged low oil prices that stifled investment in the new supply that was needed to meet that demand.

Both the 1970s and the 2000s also involved disruptions to supply well before the break point occurred. The Libyan price controversy disrupted 1.3 Mbpd (2.7 per cent of global supply or 5.5 per cent of global imports) for over 9 months from May 1970. And from April 1999, OPEC cut production by 3.3 Mbpd (4.6 per cent of global production or 7.4 per cent of global imports) for 12 months.

Production data published by BP suggest that actual production decreased by much less than the reduction in the quota. OPEC production at all times exceeded the announced quota, which has been the case almost without exception since August 1986.

Both the 1970s and the 2000s involved supply reductions at or just after the break point in the cycle. During the October 1973 Arab Oil Embargo, exports to the West were reduced by 1.6 Mbpd for 6.1 months (2.7 per cent of global supply or 5.1 per cent of global imports). After increasing supply by 4 Mbpd through the first 9 months of 2008 (following a 2.1 Mbpd reduction in the official quota from 2006 through most of 2007), OPEC reduced its production quota by 5 Mbpd (6.2 per cent of global supply or 10 per cent of global imports) in a rapid series of steps in late 2008 to the beginning of 2009 and maintained that quota for the next three years before reversing it at the end of 2011.

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Table 10 Analysis comparing the forces at the break point and in rebalancing, 1970s and 2000s

1970s 2000s

GROWTH AND DEPENDENCY drivers

Demand side

American post-war growth with large cars and non-transport oil use, plus European post-war reconstruction and Japanese re-industrialisation

Rapid Chinese economic growth, including oil demand for transport and growing private vehicle ownership

Supply side Increasing reliance on cheap oil, particularly imports from the Middle East

Libyan price controversy from May 1970 disrupts 1.3 Mbpd for 9.2 months

Expectation of low oil prices as in the previous 20 years continuing indefinitely

OPEC (excl Iraq) cuts production of oil in April 1999: a disruption of 3.3 Mbpd for 12 months

Causes of PRESSURE BUILDUP

Demand Exponential growth in the West Above exponential growth in China

Supply Producer disaffection with low prices, geopolitical tensions, and weakening confidence in the US dollar; various wars and civil wars disrupt supply

Low investment after two decades of low prices, escalating costs of new developments driven by rising prices for steel and other input costs and projects with increasing technical challenges

At the BREAK POINT

Geopolitical forces

High regional and national tensions, leading to conflict and war in the Middle East, against a Cold War backdrop

Challenges relating to major shifts in the balance of the world economy and from the rise of terrorism and asymmetric warfare.

Social forces Major economic and political stresses, particularly in the United States, following the two oil price shocks as expenditure on oil jumped from one per cent of GDP to four in 1974 and then to eight in 1979

While oil prices ran up to levels higher than the 1970s, the United States also experienced a major home loan crisis, and the Global Financial Crisis (GFC) of 2009 was the largest financial shock since the crash of 1929 and the Great Depression.

Policy forces

The United States governments policy response to the oil supply and price shocks included oil allocation, export and price controls, which turned out to be ineffective or even exacerbated the problem

The oil price increases occurred during a period of monetary stresses characterised by very low interest rates, and enormous expansion of central bank balance sheets in response to the GFC

Business forces

OPEC imposes embargo on oil exports to the West in October 1973: a disruption of 1.6 Mbpd for 6.1 months

Before July 2008 price peak, OPEC increases production quota by 4 Mbpd for 9 months, after GFC OPEC reduces by 5 Mbpd for 36 months

Environmental forces

Early awareness, but limited practical impact at this time

Increasingly stringent environmental requirements for new developments, and the prospect of future constraints on CO2

‘Magic bullets’ for REBALANCING

Demand side

Fuel switching, energy efficiency and price increases significantly changed the trajectory of demand from the path during the growth and dependency and the pressure buildup stages of the cycle

Normal price elasticity of demand

Continuing vehicle efficiency improvements

Transport sector fuel switching (NGVs and EVs)

Supply side alternatives

Investment in nuclear power, coal and natural gas as alternatives to oil; and diversification of oil supply sources to new non-OPEC supplies. Not all investments coped with the subsequent low price environment of the 80s-90s.

Prolonged high oil (and natural gas) prices catalysed the shale gas and tight oil revolution in the United States, reversing the United States oil production decline, turning a very tight market to one with excess production.

In reality, the 5 Mbpd quota reduction translated to a 2.2 Mbpd production decline, which was not sustained, but gradually increased through 2010 and 2011 as prices recovered, cancelling out the initial reduction. OPEC production throughout the period was 6 to 10 Mbpd or more above the official quota, as Figure 32 on page 45 shows.65 The data are shown in Table 10. The IEA Emergency Reserve System was not in existence during the first two of the disruptions shown. Neither the 3.3 Mbpd OPEC production cut

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in 1999, nor the 5 Mbpd production cut for 36 months after the GFC prompted IEA emergency stock drawdown or IEA collective action.

The 1999 and 2009 production cuts by OPEC were widely expected by the market, and publicly announced with sufficient notice not to ‘surprise the market’ or create a shock. Furthermore, the production cuts were predictable, because OPEC was clearly fulfilling its publicly-stated objective ‘to co-ordinate and unify petroleum policies among Member Countries, in order to secure fair and stable prices for petroleum producers; an efficient, economic and regular supply of petroleum to consuming nations; and a fair return on capital to those investing in the industry.’ The absence of any IEA collective action in response is significant, in view of the size and duration of the OPEC production cuts, because it implies IEA member countries’ collective acceptance of OPEC’s decision.66

It is noteworthy that the production cuts OPEC announced in 1999 and 2009 were of a much greater magnitude than the embargo of 1973-74 that prompted the creation of the IEA emergency response system. It is also notable that the drop in OPEC production in 1999 and 2009 (see Figure 32) was much smaller than the announced production cuts. These observations suggest that IEA member countries and OPEC member countries have reached a comfortable mutual accommodation.

A reasonable case could be made that the sequence of events reveal a tacit recognition (if not outright private acceptance) by IEA member countries of OPEC’s publicly-stated objective ‘…to secure fair and stable prices for petroleum producers; an efficient, economic and regular supply of petroleum to consuming nations; and a fair return on capital to those investing in the industry’ including OPEC’s view of what ‘fair prices’ are and what constitutes a ‘fair return on capital’ for oil industry investors.

A more nuanced interpretation would be that natural commercial and economic forces and the market constrain OPEC’s ability to manage prices, thereby reducing the risk to IEA member countries. That view is supported by the difference between OPEC’s announced production cuts, and OPEC’s actual production. In other words, there are natural limits to what OPEC might consider to be fair prices and a fair return on capital at any given moment in time. Hence risks to IEA member countries are more moderate was the case in the 1970s, or than was feared in the 1970s.

Such conclusions are perhaps not surprising, given the oil import needs of IEA member countries and the export revenue needs of OPEC member countries: in other words, their mutual inter-dependence. The conclusion from the historical experience is that on most occasions the oil market has rebalanced without IEA collective action.

3.7.2. The influence of monetary policy—market data on oil, dollars and gold

Oil is traded internationally in US dollars, and the price of oil is almost universally thought of in US dollar terms. Accordingly, the price trajectory shown in Figure 60 will be familiar to anyone who has followed the oil price in recent years.

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Figure 60 Brent crude oil daily nominal prices relative to January 2000 in US dollars

Sources: Author’s calculations using oil price data from the United States EIA and currency data from www.fxtop.com

At present, there are no alternatives to the US dollar as the vehicle currency for international oil trade. It is nevertheless instructive to view oil price data in terms other than US dollars. Interestingly, while foreign exchange rates are continuously changing, the basic pattern of oil prices is the same as the dollar in all of the major currencies: the Euro, the British pound sterling and the Japanese yen.

Figure 61 Brent crude oil daily nominal prices relative to January 2000 in the major currencies

Sources: Author’s calculations using price data from the United States EIA and currency data from www.fxtop.com

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Figure 62 Brent crude oil daily prices relative to January 2000 in the major currencies and gold

Sources: Author’s calculations using price data from the United States EIA and currency data from www.fxtop.com

Following the surge in the real price of oil during 2003-08, a popular view emerged that it could not be explained by economic fundamentals, but was caused by the increased financialisation of oil futures markets, which in turn allowed speculation to become a major determinant of the spot price of oil. Fattouh, Kilian and Mahadeva, (2012) reviewed the evidence supporting this view and found that the existing evidence does not support the idea of speculation driving the spot price of oil after 2003. The authors found that, instead, there is strong evidence that the co-movement between spot and futures prices reflects common economic fundamentals rather than the financialisation of oil futures markets.

This conclusion is consistent with the pattern in production costs shown in Figure 16 on page 24, as well as inelastic nature of both the demand for and the supply of oil, as discussed in section 2.2.8. Interestingly, the price of oil in gold terms displays a completely different pattern, as shown in Figure 62.

The data suggests that the expansionary monetary policy pursued in the past decade has been one of the factors behind the dramatic movements in oil prices, in addition to the market tightness experienced as supply struggled to keep pace with higher than expected rates of global demand growth driven by Asia.

Revisiting Figure 16 is also informative in view of Figure 62, as it shows that the upstream costs of oil production doubled between 2000 and 2008, with most of the increase occurring from 2005 to 2008, whereas annual average prices quadrupled. Tight markets do tend to drive prices well above the levels suggested by the underlying marginal costs. At the same time, it is worth bearing in mind that oil spot prices are not necessarily entirely driven by physical fundamentals of short-run supply and demand, but can be influenced by financial and monetary factors.

3.7.3. A long historical perspective on oil, dollars and gold

A number of authors have presented long price series for oil. One widely referenced example is included in the annual BP Statistical Review of World Energy, as reproduced in Figure 63. This shows that the recent oil price surge was the largest in world history, after adjusting for inflation, with the exception of 1864, shortly after the discovery of oil. In 2011, the annual average real oil price in US dollars was higher than in the boom year of 2008 before the Global Financial Crisis, and higher than after the second oil shock of 1979-80. The real price level in 2015 was similar to the level after the first oil shock of 1973-74 and before the second oil shock.

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The difference between the nominal and real dollar lines in Figure 63 reflect the deterioration in the purchasing power of the dollar since dollar-gold convertibility was ended by President Nixon on the 15th August 1971.

3.7.4. Turning points in the price cycle clearly mark the major oil pricing eras in history

Figure 64 provides an alternative view of the price history of crude oil from 1861, expressed in gold terms rather than in dollar terms. A notable thing about the view of 150 years of oil price data is the absence of the two large price spikes of the 1970s and the 2000s. Likewise, the pre-crisis depressed oil prices of the early 1970s were no more remarkable (and no more sustainable) than the depressed oil prices of 1988 and of 1933. Similarly, the high oil prices of 1979 were less remarkable than the high prices of 1920, and similar to the prices of 2005, which were perhaps more notable than the US dollar oil price peak of 2008 and 2011.

A very different picture emerges from Figure 64 than from Figure 63, characterised by oscillation about a gently rising trend line. The contrast emphasises the importance of monetary conditions for the oil market. The oil market seems to spend about a decade above the trend line, when the oil market is relatively tight or there are general inflationary pressures, or both, followed by about a decade below the trend line, when the oil market is relatively loose or there are general deflationary pressures, or both.

Figure 63 Long history of annual average crude oil prices in nominal and real US dollar terms

Sources: Author’s chart using price data from BP (2016)

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Figure 64 A long history of annual average crude oil prices relative to gold

Sources: Author’s calculations using price data from the United States EIA and currency data from www.fxtop.com

Another notable thing about Figure 64 is that the turning points align perfectly with the delineation of the major eras throughout the development of the oil industry from 1859 to the present, delineated by the pricing regimes as defined by Luciani (2010). Luciani’s pricing regime eras are presented earlier in the report in Table 1 with minor refinements and modifications, along with additional information.

The distinctive price cycles that coincide with the pricing regime eras are consistent with the ‘energy evolution cycle,’ of Figure 2. The bottom of the price cycle corresponds to the beginning of the ‘growth and dependency’ phase, the top to the ‘break-point’, followed by a ‘rebalancing’ leading to the bottom and the start of the next cycle. Viewed this way, the oil cycles are as follows.

1859 to 1892, beginning with the discovery of oil in Pennsylvania, the displacement of whale oil for lamps, the boom in demand followed by the all-time oil price-high (in both gold and real dollar terms) in 1864 during the United States Civil War, the consolidation of the refining industry, commercial control of transportation and vertical integration by John D Rockefeller, the formation of the Standard Oil Trust in 1882, and the passage of the Sherman Antitrust Act targeted against Standard Oil in 1890.

1892 to 1911, the formation of the Standard Oil Company of New Jersey, which became the parent company at the peak in 1899 and ended with the break-up of the Trust by the United States Supreme Court in 1911.

1912 to 1933, the period that began with the Great War of 1914-18 (which the United States entered in 1917) the break-point for oil came in 1920—the top of the interest rate cycle with United States Treasuries at just over 5 per cent—and was followed by the ‘Roaring Twenties’ during which the price of oil fell, through to the bottom of the cycle in the depths of the Great Depression in 1933, the year that Standard Oil of California (SOCAL) secured the first concession to drill for oil in Saudi Arabia. President Roosevelt took the United States off the gold standard, Congress nullified the right of creditors to demand payment in gold and the President ordered all privately owned gold coin, gold bullion and gold certificates to be surrendered to the Federal Reserve for $20.67 per ounce.

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1934 to 1973 was the era of posted oil prices by the ‘Seven Sisters’ and their development of low cost Middle East oil supplies, which coincided exactly with the era during which the United States government price of gold was set at $35 per ounce, while private coin, bullion and certificate holdings remained illegal, including the longest period of stable oil-to-gold prices from 1947 to 1967 during the Bretton Woods era of fixed exchange rates, and ending with the first oil crisis in 1973, after President Nixon had ended the convertibility of the US dollar for gold by foreign central banks in 1971.

1974 to 1987, was an era that began with the transfer of available and flexible spare oil production capacity from Texas to Saudi Arabia, the displacement of the ‘Seven Sisters’ posted prices with OPEC posted prices, and President Ford signing legislation permitting Americans to again own gold bullion. Those events were followed by high US dollar inflation, and rapidly escalating gold prices, paralleled by large increases in oil prices with two oil supply crises and related price shocks. A major break-point for oil came in 1979, coinciding with the Iranian Revolution, followed by the outbreak of the Iran-Iraq War. The gold price reached a record of $850 per ounce in January 1980 and then collapsed. Inflation was brought under control in the 1980s after United States interest rates peaked in 1981 with United States 10 Treasuries yielding more than 15 per cent per annum. As new production came on stream in the North Sea, and the Soviet Union strongly increased oil exports, the oil market loosened. OPEC abandoned posted prices, Saudi Arabia experimented unsuccessfully with netback prices referenced to Rotterdam refined products. Saudi Arabia’s production reduced, as North Sea, Soviet Union and other production around the world grew, but oil prices fell faster than the collapsing gold price, reaching a bottom relative to gold after the 1987 stock market collapse. The latter part of this era saw the transition to the era of market pricing regimes that was to follow. Reforms included the ‘big bang’ deregulation of the UK financial sector, the launch in the United States of WTI futures contracts on the New York Mercantile Exchange (NYMEX) enabling the trading of ‘paper barrels’ and the formalisation by Shell trading of the standardised ‘dated Brent’ over-the-counter (OTC) contract establishing it as the reference price for ‘wet barrels.’

1988 to 2015, was the Euro-Atlantic or Western market-based oil pricing era, including the launch of the IPE futures market for oil in London in 1988, and the IPE oil put and call options market in 1989. Following the collapse of the Berlin Wall in 1989, the Soviet Union was dissolved in 1991. By that time their share of world oil exports had fallen from more than 20 per cent in the mid-1980s to less than 10 per cent. Over the same period, Saudi Arabia’s share of exports had increased from 10 per cent to well over 20 per cent. In 1991, Iraq’s invasion of Kuwait disrupted 4.6 Mbpd of supply for twelve months, and the IEA responded with a collective action to release emergency stocks for the first time in its history. The 1990s were characterised by low oil (and other commodity) prices, the emergence of the view that oil prices would remain low indefinitely, and a consequent low level of investment in new oil production capacity. Following the Asian Financial Crisis in 1997, the Russian sovereign debt default in 1998 and the collapse of the Long Term Capital Management hedge fund, gold fell below $300 an ounce and reached its bottom in 2001. In 1999 OPEC announced a production cut of 3.3 Mbpd for twelve months to support prices. In China, from about 2004, GDP, energy demand, including oil demand and oil imports accelerated to double-digit annual rates. Although oil prices in dollar terms did not peak until 2008, they peaked relative to gold in 2005. In other words, after 2005, the gold price was increasing at a slightly faster rate than the oil price. United States house prices collapsed in 2005, a year that coincided with the 60th birthdays of the first of the ‘baby boom’ generation and the 40th birthdays of the last of that generation. In the Global Financial Crisis of 2008-09, gold prices collapsed, but oil prices fell further, returning the oil-to-gold price ratio to its 100-year trend line. As oil prices rebounded in 2011-14, so did gold prices in proportion. In 2015, after about five years of sustained production growth from United States light tight oil, the slowing of East Asian economic and oil demand growth and imports, and the eventual easing of numerous oil supply disruptions, oil prices collapsed. Gold prices were sustained, bringing the oil/gold cycle into a trough echoing the low points of 1892, 1911, 1933, 1973, and 1988. Saudi Arabia increased its output, in an effort to defend its oil export market share.

In 2016 looking forward the chart implies that the oil market has recently tipped from a tight/inflationary condition to a loose/deflationary condition and is on the cusp of the end of the

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current oil pricing era that began in 1988 after the transition to benchmark pricing in 1983-87. Interest rates are at all-time record low levels. If the oil/gold price pattern that has prevailed since 1892 is to continue, oil prices will remain low (relative to gold prices) for between five and fifteen years. If oil prices rise above their present levels, but gold prices also rise, the pattern that has prevailed for more than 100 years would also be maintained.

While not the only perspective on the oil market, the long-term pattern provides useful reference points amidst numerous uncertainties. Section 4.2.5 in the chapter on the outlook for the oil market provides further insights on some characteristics of the next oil pricing regime era that are already appearing.

Turning from a gold perspective back to a dollar perspective shows that interest rates are a very important part of the cost equation and influence investment decisions for high-risk and capital-intensive industries, such as upstream oil exploration and production. Figure 65 shows the long history of United States interest rates. The post-war United States interest rate cycle, which peaked in 1981, has been much more pronounced than the previous cycle, which peaked in 1920, or the one before that, which peaked in 1873.

Figure 65 Long history of United States interest rates

Source: Author’s chart based on data from http://www.multpl.com/10-year-treasury-rate

3.7.5. Risk, return and reserves: a comparison with banking reserves

In the fractional reserve banking system, banks borrow short (for example in the form of at-call deposits) and lend long (for example property mortgages). Banks are therefore required to hold a minimum level of reserves (as well as meeting a capital adequacy ratio). The confidence of depositors is essential for the system to function. ‘If all those creditors demand all that money at once, they cannot have it, for that which their debtors have used, is for the time employed, and not to be obtained.’67

Banks need to maintain reserves to ensure the stability of the banking system. In 2007-09, the international financial system experienced a major crisis that began in the United States, but spread internationally. Prior to the financial crisis, it was generally thought that capital ratios were adequate. Two quotes from 2010 illustrate this:

Five days before its bankruptcy Lehman Brothers boasted a “Tier 1” capital ratio of 11 per cent, almost three times the regulatory minimum. (Economist, 2010)

‘… in 2007, of all the major banks the one with the highest capital ratio was, believe it or not, Northern Rock. Within weeks of announcing that it intended to return excess capital to its shareholders, Northern Rock ran out of money.' (King, 2010)

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The Governor of the Bank of England noted in his speech that, ‘As the IMF have pointed out differences in capital ratios failed to predict which financial institutions would be vulnerable in the crisis (IMF, 2009).

In earlier times, banks had far higher equity than they do today, as shown in Figure 66.

Classically, in the view of Henry Thornton (1802), the central bank would act as the lender of last resort in a crisis, because it holds a monopoly in issuing banknotes. Walter Bagehot (1873) further developed Thornton’s contribution, considering how best to deal with a domestic banking crisis arising from an ‘internal panic’ at the same time as a currency crisis.

Figure 66 Change in United States and UK bank equity, 1880-2005

In the days when banks (and their customers) could not rely on governments to save them, they carried huge buffers to protect themselves against losses and drops in confidence. In the late 19th century a typical American or British bank had an equity buffer—ie, core capital—equivalent to 15-25% of its assets.

As recently as the 1960s British banks held more than a quarter of their assets in low-risk, liquid form, such as cash or government bonds.

—The Economist (2010)

Bagehot advocated that: ‘Very large loans at very high rates are the best remedy for the worst malady of the money market when a foreign drain is added to a domestic drain.’68’ The holders of the cash reserve must be ready not only to keep it for their own liabilities, but to advance it most freely for the liabilities of others. They must lend to merchants, to minor bankers, to “this and that man,” whenever the security is good.’ In Bagehot’s view:

`The problem of managing a panic must not be thought of as mainly a ‘banking’ problem. It is primarily a mercantile one. All merchants are under liabilities; they have bills to meet soon, and…are dependent on borrowing money. … At the slightest symptom of panic many merchants want to borrow more than usual… On the surface there seems to be a great inconsistency in all this. First, you establish in some bank or banks a certain reserve; you make of it or them a kind of ultimate treasury… And then you go on to say that this final treasury is also to be the last lending-house; that out of it unbounded, or at any rate immense, advances are to be made when no one else lends. This seems like saying —first, that the reserve should be kept, and then that it should not be kept.69

Banking reserves and emergency oil reserves or strategic stockholdings are not identical, but there are some parallels between them, in the sense that they are both retained, at a financial cost, as contingencies against unforeseen adverse events. Furthermore, speculative inventory demand for oil during a crisis is analogous to behaviour observed in financial panic events known as ‘bank runs.’

Current IEA policy under the IEP is that oil stockholdings equivalent to 90 days of net imports be maintained, which is equivalent to 25 per cent of annual imports. Emergency drawdowns from the Strategic Petroleum Reserve in the United States have been conducted as competitive tenders sales (with a reserve price) and as loans, repayable in the form of oil plus premium barrels (rather than financial interest). These factors raise a number of key questions: what level of reserves is needed? And: what is the best policy for deploying the reserves in a crisis? This paper does not propose to answer these questions, but rather to indicate the nuances and difficulties involved.

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Chapter 4. The Outlook for the Oil Market

The introduction to this paper looked at a number of key themes and opened the way for a comparison of the seismic oil market events of the 1970s with the tectonic shifts that became apparent in the market in the most recent decade. This chapter looks forward.

It is not the task of this paper to produce an independent outlook, nor to develop a set of scenarios. Yet it is necessary to go beyond the past and the present and to consider the future. In doing so, this chapter presents two contrasting philosophical perspectives on the oil market and attempts to reconcile them. It then provides several frameworks that are useful in understanding how the oil market is likely to develop. In the light of those frameworks, observable trends are discussed, as well as the possibilities for how the industry may unfold in the next oil pricing era. The chapter closes with a discussion of the implications for major groups of stakeholders of the evolution of the oil market.

4.1. Contrasting perspectives

There are a variety of perspectives on the oil market. A number of organisations publish oil market and global energy outlooks, including the IEA’s annual World Energy Outlook (WEO), the EIA’s International Energy Outlook (IEO), outlooks published by the Australian Commonwealth Government, the BP Outlook, the ExxonMobil Outlook, publications from environmental advocacy organisations such as Greenpeace, proprietary forecasts available to clients from consulting organisations such as Wood Mackenzie and IHS CERA, and the more qualitative Scenarios published by Shell from time to time.

The arena for oil and energy market outlooks contains a number of voices and a range of views. Energy outlooks tend to reflect the philosophy and objectives of their various authors and publishers. In some cases, the philosophical approach may be simply to calculate, illustrate and describe the expected outcomes from a set of assumptions and policy settings, with the objective of raising awareness and stimulating better-informed discussion and public debate.

4.1.1. The ‘JAM’ thesis: oil is ‘Just Another Market’

Consider first what we will call the ‘JAM’ thesis: that oil is ‘Just Another Market’, no different from any other commodity market, and therefore not requiring any special policies or institutions. This view is consistent with the research conclusion cited in section 3.5.9 that ‘…it is now widely accepted that the real price of oil is determined endogenously in global markets much like the price of other global commodities.’ Under this thesis, oil security is not a separate topic of policy concern in its own right. Issues of oil security can be reduced to questions of supply and demand, and the best way to balance supply and demand is to allow the market price mechanism to work, as occurs in most other commodity markets.

Long lead times for new supply, the difficulties of accurate demand forecasting over the time frames needed for supply side planning, and misplaced expectations of competitors’ behaviour lead to cycles of market tightening and loosening. Such patterns are evident in the oil market, and in other energy and mineral commodity markets. Nonetheless, the aspiration of delivering well-balanced markets and non-volatile prices through enlightened regulation has found appeal in various countries at various times. However, there is not a convincing body of evidence that regulators can do a better job than the market itself in overcoming the vicissitudes of supply and demand over the long-run.

On the contrary, the oil market has proved remarkably capable of ensuring supply through times of conflict as well as during periods of peace and stability. In fact, efforts of oil importing countries to prevent supply from coming to market from countries under economic sanctions, has tended to be more difficult than ensuring supply comes to market. A continual stream of disruptions around the world affects oil supply, and major disruptions have actually been few and far between. Oil prices have been volatile for 150 years and are likely to remain so due to the inelasticity of supply and demand in the short-run, and the difficulty of forecasting both supply and demand. When allowed to work uninhibited, and given enough time, price signals have never failed to balance the market, by dampening or encouraging demand, and by encouraging new supply, or discouraging production.

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4.1.2. Antithesis: oil is an exception

The antithesis to the ‘JAM’ thesis is the view that oil is an exception, and cannot be considered in the same way as other commodities. Without oil products, every economy in the world would grind to a halt. Since the early 20th century, oil has been the most important physical commodity in the world. At least one benchmark oil price is quoted daily in the finance summary of most news reports. Oil products currently fuel almost all transport of people and goods by land, sea and air: vital for domestic economies and international trade. Oil is essential for defence forces and access to and control of oil was a key strategic factor in the two world wars of the 20th century. Significant naval resources, particularly of the United States, continue to be deployed to supervise sea-lanes for oil shipping.

Oil has a high economic value, and so the international oil market represents a significant share of global economic activity: for the 50 years from 1965, global expenditure on crude oil has averaged three per cent of GWP. Oil prices affect the costs and prices of many products and commodities, influencing price inflation. Oil is significant for the trade balance of many exporting and importing countries, and oil security of supply is a high policy priority for many oil-importing countries.

Energy as oil has a high ‘form value’: the market is willing to pay far more for a GigaJoule of oil, than for a GigaJoule of most other forms of energy. This price premium over other primary energy sources arises from its characteristics. Oil has high energy density, is easy to store, transport and distribute, can be refined into a variety of petroleum products with wide applications, and is easy to use in engines and machinery that are remarkably affordable, light weight and that have stood the test of time for a century or more. Oil therefore has a major role within the energy complex, enjoying a near monopoly as a transport fuel, and is therefore crucial to the wider economy and globally significant.

4.1.3. Synthesis: oil is indeed special, but market-based approaches work best

The ‘JAM’ thesis and its antithesis are presented as diametrically opposed points of view. Yet it is clear that both of these perspectives on the oil market find support in identifiable facts. This leads to the consideration of a synthesis of the two. In reality there is a spectrum between the two contrasting views. The issue for policy-makers is not a binary one between two extremes, but a question of where is the most advisable position on the spectrum at any given time. It is a nuanced question, and one open to adjustment and refinement over time, as the oil market evolves and as the world changes.

This paper has described a number of ways that the oil market has evolved and the world changed since the 1970s, including reduced lead times for new oil supply from United States shale, the much greater flexibility and sophistication of the trading and financial markets that support physical oil transactions, and the momentous shift in the centre of gravity of global oil demand from west to east. It is also true that a number of attributes of the oil market have remained largely unchanged since the 1970s, including the importance of the Middle East in export supply and flexible production capacity. Nevertheless, the significance of the changes in the past 40 years warrants a review of the balance between the market and institutions, and how these can best complement one another.

It is helpful to review a number of frameworks to reconcile the role of market forces with policy imperatives.

4.2. Frameworks to guide views

This section presents several frameworks that are useful to enable the past to inform outlooks on the future. The first section below views oil prices through the lens of affordability. The second section considers earlier concerns about imminent depletion of the world’s oil reserves, and the replacement of those concerns with concerns about the problems of abundance, and environmental impacts. The third section introduces the Energy Policy Trilemma and the inevitability of difficult policy trade-offs. The fourth section addresses the role that the expectations of companies, investors and consumers play in the future of oil. The fifth section reviews how policy priorities have changed since 1945. The sixth and final section on frameworks briefly mentions the role that geopolitics plays in the oil market, and refers to a framework from the literature for analysis of nation states’ strategic and tactical decision-making as it relates to security of supply for importers and ensuring revenue for exporters.

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4.2.1. Oil prices viewed through the lens of affordability

Just as either high or low blood pressure is symptomatic of health problems, so very high or very low oil prices might be thought as indicative of economic problems or imbalances, signaling the need for corrective action. But ‘high’ and ‘low’ are relative terms, begging the question: Relative to what? On what basis can oil prices be considered either ‘high’ or ‘low’? One well-established approach in economics is to use inflation-adjusted (‘real’) prices for any long run analysis. In that case, the implicit answer is: relative to historical prices. Another answer to the question is: based on oil expenditure relative to all expenditure (i.e. the size of the economy). Therefore a complementary approach to focusing on real prices relative to their historical levels, is to review oil expenditures as a share of GDP. Fortunately, the research cited in section 3.5.1 shows, oil markets are utilising information more efficiently than ever before, and as this paper shows throughout, the market is self-correcting, proving repeatedly that high prices cure high prices, and low prices cure low prices.

In 1965, crude oil was a $150 billion industry: the world consumed just over 30 million barrels of oil per day (Mbpd), at an average price of $13.50 per barrel (bbl), as measured in 2015 US dollars. Half a century later, in 2014, the industry was a $3300 billion industry—22 times as large as in 1965. By 2014, consumption had increased only three-fold to 92 Mbpd, while prices were almost $100 /bbl: seven times the real price level of 1965. Then prices collapsed in late 2014 and declining through 2015, to a daily spot price low in the mid-$20 range in early 2016, just twice the 1965 real price level. In 2015, with consumption of 95 Mbpd, global expenditure on crude oil implied by market prices was just over $1800 billion—slightly less than the $1900 billion of 2009 in the depths of the Global Financial Crisis and less than half of the $3700 to $3800 billion in 2011-13.

In 1965, the global expenditure on crude oil was just one per cent of gross world product (GWP). In the five decades since, crude oil expenditure has ranged from one to eight per cent of GDP globally. Figure 67 shows the annual data. During the recent double price peaks in 2008 and 2011-12, crude oil expenditure was just below and just above five per cent of GWP. So, while real oil price levels in recent years were similar to the price levels in 1979 (Figure 1 and Figure 40), expenditure on oil as a share of GDP was comparable to the 1974-78 period and reached only about half the level of the 1979 peak.

Figure 67 shows the contrast between the level of oil expenditure as a share of GDP following the two 1970s supply shocks and following the 2000s demand surge: information that is not apparent from historical price charts. Figure 67 also shows that whereas the 1970s price shocks resulted in very steep and sudden increases in oil expenditure as a share of global GDP, the demand surge of the 2000s resulted in less steep increases in prices. In both cases, the expenditure changes followed the pattern of the price changes. There was a large increase in price and a small moderation in demand growth (or a small decrease in demand), until demand balanced with available supply.

The World Bank publishes estimates of natural resource rent from crude oil as a share of GDP, as shown in Figure 67. Rent historically has represented two-thirds to three-quarters, and costs one-third to one-quarter, of world expenditure on oil at international market prices. Oil expenditure as a share of GDP is just one perspective for looking at prices.70 It provides a convenient rule-of-thumb metric for viewing oil in the context of the wider macro-economy. More complete and rigorous analysis of the effects of exogenous oil price shocks on GDP requires the use of sophisticated dynamic stochastic general equilibrium (DSGE) modelling.71

The contrast in which the real price levels of 1979 have been revisited, while oil expenditure as a share of GWP was only just over half of the level in 1979, reflects economic growth in the intervening years, as well as the reduced reliance on oil and the lower share of demand satisfied by oil in the global energy system. In economic terms, the price inelasticity of demand is the dominant factor in the short-run, but the income elasticity of oil demand is more significant than the price elasticity in the long run. The effect of incomes on oil demand is very significant in any outlook for oil because of the rapid increase in incomes in Asia in recent years, and the momentum in that trend.

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Figure 67 World crude oil expenditure and implied cost of production as share of GWP

Sources: Author’s calculations using data from the BP Statistical Review of World Energy, 2016, The World Bank and the Federal Reserve Bank of St Louis (2016) Notes: The implied cost of production as a share of GDP has been estimated by subtracting the estimated rent from the implied expenditure on crude oil. Implied expenditure has been estimated as the simple annual average of the market price, multiplied by annual consumption volumes. The same calculation can be made for oil exports and imports. It should be noted that when those numbers are compared with publicly available data on crude oil import and export values, it is found that the import and export values are lower. If the import-export data is correct, that implies actual export-import prices are on average lower than market prices, at least in trade between some countries. That suggests long-term contracts do not always necessarily reflect the average of spot market prices throughout a year. Hence the term ‘implied expenditure.’

The historical data suggests that oil expenditure below two per cent of GWP, as was the case before 1973 and throughout most of the 1990s can be considered low, and above three per cent of GWP, as was the case from 1974 to 1985, can be considered high. At the current level of global oil consumption, an oil price just under $50/bbl is about two per cent of the current level of GWP and $70/bbl is about three per cent of GWP. From the perspective of historical prices, this perspective would indicate that prices below $50 are indicative of a loose market, and prices above $70 are indicative of a tight market.

If GWP continues to grow at a faster rate than oil consumption, as it has for more than three decades now, then the real price levels above which the market can be considered to be tight and below which it can be considered loose will continue to increase. In other words, higher real oil prices become more affordable over time.72 This would be consistent with an expectation that long-run marginal costs of production tend to increase over time, even with technological advances.

4.2.2. Policy considerations relevant to oil—depletion, abundance and the environment

In 1972, the United Nations Conference on the Human Environment took place in Stockholm, Sweden. That has come to be seen as a landmark event, followed by the 1992 United Nations Conference on Environment and Development in Rio de Janeiro and the 2002 World Summit on Sustainable Development in Johannesburg. Yet, in 1975 what we know today as the modern environmental movement, and the international system that governs sustainable development was in its infancy.

During the 1970s, the crisis in oil markets was combined with the emergence of concerns about the environment. The widespread concern—as expressed in the publications of the Club of Rome and others—was that the world would soon ‘run out of oil.’ This concern reached all the way to the White House. As President Carter said, ‘We need to have a realization that we have about thirty-five years of oil left in the whole world. We are going to run out of oil.’73 In the United States, the fear of imminent global oil depletion was accompanied by anxiety over rising dependence on imported oil.

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Today, the fear that the world will soon run out of oil has been replaced by the fear that there is too much oil and that the world cannot afford to use all of the oil in the ground, because increased concentration of carbon dioxide (CO2) from combustion emissions will lead to dangerous climate change. This is expressed in calculations of a ‘global carbon budget’ and estimates of ‘unburnable carbon’ and are embodied in the movement warning investors about ‘stranded assets.’ These developments represent a significant shift in policy rationale since the 1970s. Interestingly, while the diagnosis of the problem has reversed—from the world running out of oil to the world containing more oil than we can afford to consume—some of the policy prescriptions today are the same or similar to those in the 1970s, both in the United States and a number of other countries. Examples include policy drives for greater energy efficiency, fuel substitution to less carbon-intensive energy sources including natural gas, nuclear power and renewable energy.

In November 2015, at the 21st Conference of the Parties to the United Nations Framework Convention on Climate Change (UNFCCC) agreed at Rio de Janeiro in 1992, the Parties to the UNFCCC agreed to limit increases in global average temperatures by pledging Nationally Determined Contributions to limit emissions of CO2 and other greenhouse gases (GHGs). Coal is in the front line of initiatives to reduce CO2 emissions. Nevertheless, oil is a carbon emissions-intensive fossil fuel, and there no practical prospects for capture and sequestration from the mobile engines that burn it. The extent to which the Paris Agreement affects demand for oil remains to be seen. However, the existence of the Agreement is a notable difference between 2015 and 1975.

4.2.3. The Energy Policy Trilemma: trading off security, affordability and sustainability

Previous chapters explains the oil market with reference to:

Fundamental drivers of supply and demand, and of export and import trade

Physical factors relating to the geology and engineering of oil exploration and production

Economic drivers and relationships behind costs and prices and their interaction

Financial realities of investment and operations, trading and logistics, refining and marketing

Market relationships between oil prices, money, interest rates, gold and other commodities

All of these physical and financial, technical and commercial quantitative frameworks are needed for making sense of the oil market. In addition to those quantitative frameworks, a qualitative framework is needed to represent the influence of policy on the oil market, and other energy markets. The framework involves standing in the shoes of policymakers, and is called The Energy Policy Trilemma, represented by the schematic in Figure 68.

Energy prices are of political concern in every country. This applies to the prices of liquid petroleum products, as well as of electricity and gas. Accordingly, every country in the world has an energy policy, whether it is large or small, rich or poor, and regardless of its system of government. Traditionally, governments sought to balance energy security of supply with energy affordability. In more recent times environmental sustainability has been added as a third energy policy objective.

Most of the time, in most countries, the three energy policy objectives are in tension with one another. The pathway to achieve one objective is usually straightforward. Achieving two objectives at the same time is difficult. Achieving all three simultaneously is usually impossible. Increasing security tends to have cost implications. Reducing emissions usually increases costs. Changing the share of the energy sources in the fuel mix has implications for each of the three policy objectives. Therefore, trade-offs are normally required.

Among the three main fossil fuels, gas has emission advantages over coal and security advantages over oil, but tends to face cost challenges outside North America. Coal has cost and security of supply advantages over oil and gas, but has the disadvantage of high emissions. Oil faces challenges on all three fronts, being the most expensive of the three fossil fuels, having relatively high emissions, and being the subject of security of supply concerns. Oil retains its market share based on its many advantages as a transport fuel: for transport, the alternatives currently have even higher costs.

In the difficult business of making the trade-offs required to formulate energy policy, a priority order usually emerges, either explicitly or implicitly between the three objectives. Views tend to differ between stakeholder groups on the preferred priorities, which is the essence of energy policy debates. Governments have the challenging task of settling on a particular set of trade-offs.

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The priorities afforded to each of the policy objectives vary between countries, reflecting the different circumstances of each country. The priorities can also change over time within a country. Sometimes exceptions arise to the rule that trade-offs are required between the three objectives, which generally occurs when there is a change in circumstances.

Figure 68 The Energy Policy Trilemma

Source: Author’s diagram

The oil shocks of the 1970s are one example. For many governments in oil importing countries, energy security became a higher priority. At the same time, the price of oil increased relative to other energy sources. That changed the economics of energy conversion and utilisation. Heightened security concerns resulted in changes to government policy, and changes in relative prices changed market responses via both supply and demand. The major strategies to diversify away from oil, reducing its share in the fuel mix, included increased use of coal, gas, and nuclear power. Increased use of gas and nuclear power improved fuel diversity and increased security of supply, reduced costs because oil prices had stepped higher, and (incidentally) reduced emissions. Increased use of coal resulted in increased security of supply and reduced costs. The step changes in relative prices resulted in the energy sector seeking a new equilibrium, and during that transition the tensions within the trilemma were greatly reduced. When a new equilibrium was eventually found, by which time policy priorities had also changed, the difficult trade-offs within the trilemma again became apparent.

Two other exceptions to the general rule of tension and trade-offs are worth noting: the recent shale gas and light tight oil revolution in the United States, and the loss of the Fukushima nuclear power plant in the Great East Japan Earthquake and tsunami of March 2011. In Japan, the reduction in availability of generation from nuclear plants changed the fuel mix, and resulted in adjustments to climate policy.

The shale fracking revolution greatly expanded the supply of natural gas, liquids and oil, introducing significant quantities of infra-marginal supply. In the case of gas in particular, the large and unexpected new supply drive down the price of natural gas relative to coal in the United States, changing the economics of power generation sufficiently to have a material effect on the fuel mix. The dispatch patterns of existing plants changed, the construction plans for new plants were affected (plans for a number of new nuclear reactors were shelved) and plant retirement schedules were changed.

The key implications from the analysis in this paper—in terms of the trilemma framework as it applies to oil—are that oil cannot be viewed in isolation from other energy sources, and energy security is one objective among several requiring challenging trade-offs by policy-makers.

4.2.4. The key role of expectations

Expectations often turn out to be wrong. However, expectations also play a key role in influencing behaviour in all markets. Expectations of future prices are a key determinant of investment decisions by

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producers. Price expectations are, in turn, influenced by expectations about demand and competing supply, as well as expectations about royalties and taxes. Expectations about demand and supply are also linked with expectations about economic growth, technological development, costs, and policy settings; and oil price expectations are also an important determinant of decisions by consumers, for example in vehicle purchase decisions. Expectations of higher oil prices lead to greater investment in more efficient engines, or in technologies that use alternative fuels. Expectations of lower oil prices lead to the opposite outcomes.

How—and to what extent—the oil market changes or remains unchanged between 2015 and 2050 will be influenced by the complex interaction of market forces and policy settings. The main uncertainties include the trade-offs that governments make between competing policy objectives; the marginal source of oil supply and its influence on prices, in particular the scale and long-term competitiveness of light tight (shale) oil production and its influence on the supply curve.

Given the changes that have characterized the history of the oil market, there will continue to be changes, and it would be inadvisable to be rigid in how we think about the industry. Despite changes, competitive threats and policy challenges, the capitalisation of the industry suggests that the prevailing view among investors is that oil will remain in demand and that the industry has a long-term future. In other words, investors are not currently behaving as though oil is a sunset industry.

4.2.5. The influence of policy priorities on the outlook for oil

Consideration of the Energy Policy Trilemma underscores the importance of clearly articulated and transparent priorities in shaping energy policy. In practice, the conditions prevailing in the oil market influence energy policy settings just as much, if not more, than energy policy settings influence the oil market.

Table 11 Shifts in the priority of policy concerns since World War 2

Demand centre: America Atlantic basin Transition east Indo-Pacific

Approximate period 1945-1973 1974-1999 2000-2015 2016-…

Dominant policy priorities: this is a highly simplified summary of the major themes of each era

Price: low and stable prices played a key role in post-war recovery. Security was a lesser issue.(a) Environment not yet a concern.

Security again pre-eminent, followed by price, which was gradually displaced by the environment

Environment became a headline concern in the West. In the East, price was increasingly overtaken by supply security concerns

Increasingly complex 3-way tension: security, environment, and price

Demand dominated by US, EU + Japan OECD Non-OECD Non-OECD Asia

Imports dominated by Europe Europe + US Europe + US China (+India)

Exports dominated by Concessionaires OPEC OPEC OPEC (?)

Supply most influenced by US & OECD OPEC…NOCs …US shale… key uncertainty

Oil price set by ‘Seven Sisters’ posted prices / balanced in Texas with TRC regulation

OPEC posted prices…then benchmarks and futures trading, OPEC balancing

Price discovery in a mature market balanced by OPEC

Market forces with questions about OPEC’s role in balancing

Global monetary system Bretton Woods Floating USD …under stress RMB enters SDR

Source: author’s analysis Note (a) Security had of course been a leading policy concern during the war during and between the wars. That was more especially the case for the UK, European countries and Japan than for the United States, whose oil supplies were abundant and secure at that time.

Table 11 expands on Table 4 from page 62, adding a column and indicating the Indo-Pacific as the emerging new oil demand centre. Market trends and current institutional arrangements suggest that oil outlooks need to take into account an increasingly complex three-way tension between energy security, constraints embodied in international environmental agreements, as well as prices and their economic

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implications. This contrasts with earlier periods: prices were the primary focus during the regulatory era; security became the top policy concern following the oil crises and the environment came to dominate the agenda in many countries and internationally, at least prior to the GFC. The three factors are ever-present and interacting, but the emphasis varies over time and between countries. Maintaining a stable energy policy can be a challenge because circumstances can change, as can the emphasis or priority given to policy objectives.

4.2.6. The role of geopolitics

In a recent paper published by the Center for Global Energy Studies at Columbia University, Pascual74 (2015) notes in the opening sentence that ‘[e]nergy and geopolitics have always been closely linked.’ In the paper, Pascual:

…provides a framework to understand the relationships between energy geopolitics and energy markets. An underlying premise of this paper is that neither energy markets nor foreign policy are static. Thus, to understand how energy markets and foreign affairs intersect, we have to understand the dynamics between the two. Strong national policies require us to understand how nations might influence energy markets and how radical change in energy markets affects the national interests of countries. In addressing the two together, this paper provides a new analytic foundation for governments and the private sector to assess how investment decisions and government policy will influence national security, economic growth, and environmental sustainability.

It is notable that the last sentence of the quoted paragraph links investment decisions and government policy to the ‘Energy Policy Trilemma’ discussed earlier. Under the rather provocative heading ‘Energy as a geopolitical weapon?’ the Columbia CGEP paper sets out a framework for analysis called ‘The Rules of Six.’ The method involves a matrix of ‘six tactical interventions that capture most tools nations could use as an instrument of national security policy to intervene in energy markets,’ and ‘any given intervention must be assessed against six market and institutional factors that will influence the desired outcome.’ The six interventions are listed in the following order: (1) Block Exports (United States and European sanctions on Iranian oil exports are provided as an example); (2) Constrain Production Capacity by blocking investment and trade (described as underpinning current United States and European sanctions on Russia); (3) Flood Markets to drive out new competitors, acquire market share, or punish others with a high stake in expanding market share is a potential producer strategy; (4) Starve Markets as a dominant supplier strategy, illustrated by well-known examples; (5) Assist Friends is illustrated by several examples, and (6) Change the Fuel Mix, with references to coal, and renewable energy. The six prevailing market factors against which the interventions are assessed are listed as: (1) Market Scale; (2) Investment Flows; (3) Coalitions; (4) Ability to Sustain (5) Speed and (6) Self-Risk.

The ‘Rules of Six’ framework provides an analytical tool that can be used for forming expectations about likely future courses of action by governments, and how those actions interact with and may be constrained by the realities of the market. The framework can also be used to review historical events, and may provide insight into why events unfolded as they did. For example, prevailing market factors help to explain why large magnitude, long duration oil supply disruptions are very infrequent. The factors also help to explain why, when a large disruption occurs, it cannot continue indefinitely.

4.3. Trends and possibilities in the next oil pricing era

Outlooks are notoriously difficult, and commodity outlooks can be particularly challenging. Looking back over long-run oil and energy outlook publication series from various organisations, from the IEA to the EIA to oil companies and others, a common theme is that all analysts ‘got things wrong’ at some point. Another common theme is that projections tend to show a large influence from the conditions that happened to prevail in the year of publication and the few years immediately before. That influence tends to be apparent in reference cases, in assumptions—particularly price assumptions—and can even find its way into scenarios, which are usually prepared with the intention of encompassing a broad range of possible futures.

With those caveats, it is possible to make some observations about the next oil-pricing era, which appears to be commencing at the time of writing. Observations are grouped under clear trends with strong momentum and changes that may occur, based on early signals and inferences and suggestions from economic history.

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4.3.1. Clear trends in train with strong momentum

As a result of the eastward shift in oil demand and oil imports, as well as the reduction in United States imports due to domestic light tight oil production, the IEA share of world oil imports is falling rapidly, as Figure 69 shows. This is the major theme of the new era, and perhaps the clearest strong trend.

Oil imports will become increasingly dominated by Asia and the Indo-Pacific region will be the undisputed centre of the world’s oil import markets. Market forces are expected to play an increasingly important role in price formation, facilitated by the growing size, complexity, reach and sophistication of global markets.

In the Indo-Pacific era for the oil market, the trends for oil demand are well established, driven by underlying demographics, social and economic development and technology trends, all of which have strong momentum. The following trends are clear:

Figure 69 The IEA share of world oil imports is falling rapidly

Source: author’s chart based on data from BP Statistical Review of World Energy, 2016

Non-OECD countries’ share of imports is poised to overtake OECD countries’ share of imports, possibly in 2016 and almost certainly before 2020 (Figure 69)

Natural gas will continue to grow in significance as a primary energy source, slowly converging with the global market shares of oil and coal at somewhere between 25 and 30 per cent of primary energy supply (see Figure 47)

Traditional formula-driven gas-to-oil price linkages for pipeline gas will gradually continue to weaken as gas pricing hubs grow, United States LNG exports ramp up and as the widened Panama Canal transits a growing LNG tanker trade,75 and as challenges to destination clauses in gas sales and purchase agreements from major LNG importers, such as Japan, gain traction.

Strategic storage by major oil exporters in major oil import countries—already commenced between Saudi Arabia and South Korea and between Saudi Arabia and India—continues.

China’s build-up of its Strategic Petroleum Reserve is expected to reach its goal of 90 days of net imports ahead of the government’s 2020 policy goal.

On 30 Sep 2016, the Chinese renminbi (RMB) formally entered the IMF SDR currency basket, becoming the fifth currency included.

China continues to emerge as a major economic and world power. Chinese offshore infrastructure investment grows, with a significant portion of the portfolio of the Asian Infrastructure Development Bank targeted to oil and other energy-related infrastructure.

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IEA reforms designed to increase collaboration with China, as well as India and other emerging markets such as Indonesia and Thailand, continue. OECD country Mexico becomes an IEA member, adding to the list of oil exporting member countries.

Central banks around the world continue to rebuild their gold reserves, a phase that began after the financial crisis in 2008, following the era of central bank gold sales (OMFIF, 2016).

The United States’ share of total worldwide official gold holdings is expected to decline. ‘Showing the shift to a more diversified world monetary system, the United States now accounts for just 25 per cent of total official holdings, compared with 19 per cent in 1900, 33 per cent in 1920, 76 per cent in 1940, 44 per cent in 1960 and 23 per cent in 1980. In future years, as economic clout moves away from advanced economies, developing nations are likely to build up further gold reserves as a proportion of total official holdings stocks.’ (Marsh and Robinson, 2016).

Developing countries remain hesitant about relying unduly on reserve holdings in dollars. China in particular seems to be following a strategy of using gold to counter the weight of the dollar. China is expected to continue to build its gold reserve holdings.76 The reserve holdings of the PBOC become gradually less weighted to United States Treasuries and more weighted to gold. (Marsh and Robinson, 2016).

Foreign Direct Investment by China and other oil importing countries in oil exporting countries and NOC-with-NOC partnerships linked to bilateral oil trade deals. Examples include China and Russia,77 as documented by Henderson and Mitrova (2016), and Chinese oil company deals in Africa and the Middle East. As such deals grow in significance, they become a competitive commercial challenge for the western IOCs, which need to adapt their commercial and business models.

For the foreseeable future, the US dollar remains the only currency able to play the role of vehicle currency for international commodity trading. At the same time, China has grown to become the second largest economy in the world. Respected authors, including Lowe (2014), have published views on the importance of the internationalisation of the RMB.78 Lowe refers to research by Eichengreen et al (2014), which reviews the implications of RMB internationalisation for oil trading:

Despite the global financial crisis, the U.S. remains the major global “lender of last resort” in the event of a liquidity crisis, and so long as this is the case it will be an important factor underpinning the pricing of most commodities in $US. However, some studies on choice of currency for commodity invoicing also emphasise the importance of threshold effects or “tipping points”. By way of example, a recent study on oil invoicing uses a network effects model to examine the conditions under which either a complete switch in invoicing currency or parallel invoicing in more than one currency might occur, and conclude that two main conditions would need to be met: oil exporters would need to expect that a certain minimum number of other oil exporters will also begin to use the new invoicing currency; and the information costs associated with quoting prices in two currencies are low.

The report states that ‘China has had some limited success in pushing for some of its commodity trading partners to invoice in RMB—including Iran, Nigeria and some of the ex-Soviet states.’ It is notable that China’s imports from that group of countries are dominated by oil (and other hydrocarbons).79 The report suggests that ‘If one large commodity exporter “broke ranks”, invoiced in RMB and received a significant price advantage in the process that outweighed their currency hedging costs, this could potentially have a snowballing effect. However, discussions with senior executives at a number of large [Australian] commodity exporting companies suggest that, at least at this stage, they are not seeing any pressure from Chinese importers to invoice in RMB. In summary, given the above factors and the potential for both parties to gain, it is easy to envisage a significant increase in RMB commodity invoicing and settlement over the course of the next decade.’

As noted above, the RMB was recently included in the basket of Special Drawing Rights (SDR) currencies with the International Monetary Fund (IMF), a significant milestone. Table 12 shows the change in composition of the SDR basket.

Table 12 Change in composition of the IMF Special Drawing Rights currency basket

Currency effective: 1 Jan 2011 1 Oct 2016

USD United States dollar 41.9 41.73

EUR European Union euro 37.4 30.93

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RMB Chinese renminbi — 10.92

JPY Japanese yen 9.4 8.33

GBP United Kingdom pound sterling 11.3 8.09

Source: IMF (2016a).

Historical data, trends, fundamentals and economics all suggest OPEC will continue to dominate exports. While already very significant, particularly to Japan, Korea, China and the ASEAN countries, the Middle-East-to-Asia oil trade routes will become more important. Oil exports by pipeline to China will become increasingly important to Russia, in addition to established oil exports by pipeline to the European market as originally opened up by the former Soviet Union.

Given the demand growth in Asia, and assuming Asia continues to be oil short, this trend is likely to continue through to 2050. A number of factors material to the oil market are currently expected to continue unchanged:

The oil market pricing era that began in the late 1980s continues.

The US dollar retains its role as the international vehicle currency for oil and commodity transactions for the time being, due to the lack of alternatives able to meet all of the criteria.

Official United States Federal Reserve Bank gold reserves are expected to continue to remain unchanged at 8134 tonnes, the largest gold holding in the world.

In addition to the clear trends, there are signs of changes that could plausibly occur in the Indo-Pacific era for oil markets:

NOCs of oil importing countries become as significant as NOCs of oil exporting countries

The roles of London and New York in oil trading and financial markets begins to be challenged by Singapore and Shanghai

The role of the dollar as the sole international vehicle currency for oil trade, begins to be challenged by the RMB, which starts to be used for bilateral oil trade between Chinese NOCs and oil exporting NOCs.

4.3.2. Significant uncertainties and implications

Perhaps the question of greatest uncertainty among the major variables of interest for economic trends relevant to the oil market is: what will be the source of most influence on global oil supply?

As section 2.2.13 on page 55 shows, it remains to be seen how long the United States shale oil industry in its present form and structure can survive low oil prices, not to mention the possibility of real interest rates reverting to more historically normal levels, and the scale and character of the industry after oil prices have recovered from their present low levels. From an industry perspective the issue is how much United States light tight oil production is sustained at low prices, and how flexibility light tight oil production responds to oil price changes.

The deep trends described above have significant implications for companies, including both IOCs and NOCs, for countries including both oil exporters and oil importers, for countries in the West and in the East, for high income industrialised countries and emerging economies, and for international institutions, including OPEC and the IEA. Some of those implications are discussed in further detail in section 4.4 below.

In considering the implications of the new Indo-Pacific era, the differences and similarities in the oil market from 1975 to 2015 identified in section 3.4.11 should not be forgotten:

Market information and data transparency has increased enormously.

Oil has a smaller share of the fuel mix in the global economy.

Oil now has only a very small presence in the power sector.

However, oil remains almost completely dominant in the transport sector worldwide.

Oil at the same real price levels as 1975 is more affordable relative to GDP in 2015.

Global pressures on new oil supply and prices have been eased by the shale revolution.

Policy makers are now concerned about ‘unburnable carbon,’ not ‘running out of oil.’

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Yet the policy prescriptions remain similar and involve trying to reduce oil use.

Oil demand has shifted from being OECD/Atlantic-centric to being Asia/Indo-Pacific-centric.

4.4. Implications for major stakeholder groups of the evolution of the oil market

The implications of the similarities and differences in the oil market since 1975 depend on the perspective from which they are viewed. This section views the implications from the perspective of oil importers, oil exporters, key countries in Asia, IOCs, NOCs and international institutions.

4.4.1. Implications for oil importers including key countries in Asia

For oil importers, extensive high quality market information and data transparency reduce the sense of uncertainty and panic about events affecting oil supply. This is positive from the level of policy-makers through to businesses to ordinary consumers. All parties are today far more informed on the numbers than was the case in 1975. Oil exposure is now largely an issue for the transport sector. Neither the power sector nor the industrial sector is as exposed to oil prices as they were in the 1970s. Transport is vital to all economies and increases in the cost of transportation ripple through to the prices of food, as well as other goods and services. The lower share of oil expenditure relative to GDP means that oil-importing economies had more resilience in the face of high oil prices in 2015 than was the case in 1975, and this higher level of resilience is likely to persist. The easing of pressures on new oil supply by the shale revolution has had the largest effect in the United States, which has benefited from both a volume effect through reduced import requirements and a price effect. Other oil importing countries have benefited from the price effect. The benefits are likely to continue for both the United States and other countries. The fact that oil is more affordable for oil importing countries, and their economies are more resilient to high oil prices than they were in the 1970s helps explain why the economic benefits of a collapse in oil prices has not been as noticeable in 2015-16 as in the 1980s. Nevertheless, the combination of increased affordability and shale oil relieving upward pressure on prices in the medium-term are both positive developments for oil-importing countries.

For key countries in Asia, including China and India, it is clear that sufficient oil reserves exist globally, at affordable prices to fuel the transport sectors of their rapidly growing economies. Counterbalancing this is increasing international pressure to constrain fossil fuel consumption in order to limit CO2 emissions, while also managing local pollution concerns. The extent to which such policy ambitions affect oil consumption remains to be seen. Advances in technology and the availability of alternatives mean that emerging economies today are able to pursue a less oil-intensive development path (and possibly a less carbon-intensive path in general) than the United States in the post-war growth era of the 1950s and 1960s that preceded the crises of the 1970s. The rapidly growing economies of Asia are experiencing increasing dependence on oil imports, which is in some ways a parallel of the United States experience of the 1970s. Asia’s dependence on oil exported from the Middle East is another interesting parallel. However, these pressures are in turn mitigated by all of the factors noted above.

While all large countries in Asia are net oil importers, many have National Oil Companies active in offshore investment in upstream oil production. Those companies play a key role in securing access to oil supply on behalf of their national government. Some parallels are evident with the role played by the offshore investments of the IOCs from the United States and the UK during the 1950s and 1960s.

4.4.2. Implications for oil exporters and their NOCs

For oil exporters, improved data in the hands of policy makers and investment decision-makers in oil importing countries results in a more level playing field, reducing some of the natural information advantage of the producer-exporter over the importer-consumer. At the same time, such transparency helps to reduce misunderstanding and provide a basis for dialogue and predictability. Oil exporters also now have data from four decades of oil consumers’ responses to very large price movements and are more ‘integrated’ in the market.

The distribution of conventional oil reserves remains quite concentrated today, as it was in the 1970s. The National Oil Companies (NOCs) remain very significant and influential as a result. The shale revolution is one change that has brought the greatest uncertainty for the NOCs. The availability of detailed data—on oil demand, price responsiveness and the economic understanding that accompanies it—has given oil

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exporters a far deeper understanding of both short-term and long-term demand behaviour than was available to them in 1975. Although oil retains for the time being a near-monopoly position as the fuel of choice for land, sea and air transport, alternatives are in view, and under active development. Examples include natural gas vehicles and ships, as well as electric vehicles that can be recharged from the grid. After the experience of oil being displaced from the power sector and industry since the 1970s, oil producers are very conscious of long-term competitive threats.

4.4.3. Implications for IOCs

The International Oil Companies (IOCs) have adapted to the changes in the oil market over the decades, and continue to play an important role in the exploration and production of oil around the world. Although oil’s share of the global energy supply has reduced significantly since the 1970s, it is a much larger industry today, exploration is far more sophisticated, and new oil projects require far more capital and more advanced technology to develop. While NOCs have become more influential, the IOCs have been through a number of mergers and acquisitions, and are much larger companies than they were in the 1970s. With large, strong balance sheets, they are well positioned to manage risk on major conventional oil developments in very deep water and remote locations, as well as to acquire smaller shale oil producers with a narrower portfolio that may have difficulty managing oil price risk.

4.4.4. Implications for international institutions

Greater understanding of market economics, the limits of pricing power, and the importance of market share, all developed from practical experience, are material differences since the 1970s that carry major implications for the strategy and behaviour of OPEC. The eastward shift in centre of gravity of OPEC’s markets from the United States and Europe to Asia will bring with it changes in oil diplomacy, and the nature of the commercial and international partnerships that accompany it.

The differences and similarities of the oil market in 2015 compared with 1975 also have a number of implications for the OECD economies and IEA member countries. Overall, IEA countries are in a far better position in 2015 than they were in 1975. Greater data transparency, more information, less reliance on oil as an energy source, oil expenditure as a smaller share of the economy, new sources of supply, and success in improving the efficiency of oil (and other energy) use are all valuable achievements, and a testament to the collaborative work under the umbrella of the IEA. At the same time, the eastward shift in the balance of oil demand and especially of oil imports means that the approach to energy security can no longer be OECD-centric nor Atlantic-focused (or Euro-Atlantic plus Japan).

New thinking will likely be required to ensure that international institutions are well suited to the challenges of the 21st century, and not constrained by approaches that were crafted in response to the crises of the 1970s.

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Chapter 5. Summary and conclusions

5.1. Summary

In the early 1970s, spare oil production capacity shifted from Texas to Saudi Arabia. This was significant because flexible, low cost spare production capacity confers the ability to increase supply to meet demand at a given price level in the global market. Conversely, the willingness and ability to idle production capacity allows supply to be reduced to sustain prices at a given demand level. After the events of the 1970s—during which the United States government tried and failed to manage oil prices—the market moved from a system of regulated or posted prices to spot prices. Before 1973, the Texas Railroad Commission played a key role in balancing oil supply and demand. Since 1973, Saudi Arabia, in co-ordination with fellow OPEC member countries has played the leading role in balancing supply and demand and influencing market prices, although there are clearly limits on Saudi Arabia’s ability to control prices.

A financial market in futures and option contracts emerged to complement the physical market, which has now grown to be one of the largest, deepest and most liquid markets in the world. Oil derivatives are used by currency traders, by producers and consumers wanting to hedge long or short positions not only in oil, and also by gas producers, exporters, traders, importers and large consumers to hedge gas price risk where gas is price-linked with oil. The futures market complements the spot price by providing a forward price curve that currently extends 72 months or six years into the future. Although most trading or ‘open interest’ is concentrated twelve months ahead, the forward curve provides a current market view on the direction of prices. While the forward curve moves up and down with the spot price, the back end of the curve is less volatile than the spot price and changes in the shape of the curve reflect market information and expectations. None of that financial and market sophistication existed in the 1970s.

Before the first oil shock, data and information on oil supply and demand was opaque and difficult to obtain. Today the oil market is far more transparent. In addition to the constant stream of real-time market prices and other information from financial markets available on trading screens around the world, there is readily-available data on fundamental supply and demand, imports and exports, trade flows, costs of production down to the field level, for example. Some of the data are publicly available; other data is available by subscription. In the early 1970s, such data were unavailable, or proprietary and partial, not global in scope. After the formation of the IEA in 1974, and the United States EIA in 1977, data collection became more systematic. In 2001, APEC, Eurostat, the IEA, OLADE, OPEC and the UNSD launched the Joint Oil Data Exercise, which broadened within a year to cover 90 per cent of oil supply and demand and became the Joint Oil Data Initiative. Now the Joint Organizations Data Initiative, JODI publishes world databases for oil and gas. Data is indispensable for the market to function effectively, and enables better decision-making.

The role of oil in the global economy has undergone a sea change since the 1970s. Following the demand growth and increasing oil dependence of the 1960s, and the pressure build-up of the early 1970s, the rebalancing of the late 1970s and 1980s reduced oil’s share from almost half to one-third of global primary energy.

The efficiency of energy use, including oil use was very low before 1973. It has continuously improved since 1973, partly in response to prices, and partly as a result of government policies. Japan is probably the leader in such endeavours.

The geographic distribution of oil demand is part-way through a profound shift from west to east, with the rise of China, India and the ASEAN economies. This is having a large structural effect on trade flows, such that the Asia Pacific market continues to increase in importance, while the Atlantic market decreases in importance.

The emergence of a new source of oil supply onshore in the United States—from shale beds that were previously considered uneconomic—further reduces Atlantic basin oil imports, adding weight to the eastward shift in trade flows due to Asia Pacific demand growth. Views differ as to the level of United States light tight oil production that can be sustained at price levels materially below the recent historic highs, and at interest rates higher than the current historic lows.

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Before 1973, upstream technology for oil and gas production was limited to onshore conventional fields and fixed jack-up structures in shallow water depths and moderate well drilling depths. Today, oil supply includes unconventional onshore developments unlocking light tight oil in shale beds using horizontal drilling and hydraulic fracking particularly in the United States, ultra-deep water offshore developments around the world, fields in high arctic regions, very deep wells, directional drilling, tar sands in Canada, and experimentation with coal-to-oil and coal-to-liquids production in China. More technically challenging sources of supply are economic today than was the case four decades ago. The supply curve has been dramatically extended, and proven reserves greatly expanded. Marginal costs are higher, but have nonetheless been proven to be affordable.

Before 1973, oil exports were dominated by OPEC. Oil exports are still dominated by OPEC, but not to the same degree. At the same time, there have been changes in resource nationalism, the role of host country governments and the role of national oil companies. The trend to greater host country control and higher shares of oil rent was already underway before the oil shocks and gathered momentum through the 1970s. Concession agreements, which were still in existence in the 1970s have been almost entirely consigned to history. Production sharing agreements are the norm in the industry.

Since the 1970s, the influence of the NOCs has tended to increase and that of the IOCs to decrease. The degree to which OPEC has been able to influence the market, and the perception of its influence has fluctuated. Nevertheless, OPEC is generally perceived as being far less influential today than in the 1970s. This is the case despite the continued high concentration of oil exports (to a greater degree than oil production) among OPEC members, and Saudi Arabia’s near-monopoly over flexible spare production capacity that can be used to ‘swing’ production to balance supply with demand. Concerns in oil importing countries in the Atlantic and Pacific basins about security of supply from Saudi Arabia, the Middle East, North Africa and West Africa today tend to be more focused on the scope for non-state entities such as international terror organisations (and their non-recognised self-proclaimed states) to disrupt supply, rather than sovereign state decisions to disrupt supply. The potential for regional conflicts to escalate into larger wars is another risk. The vulnerability of the supply chain, particularly shipping lane ‘choke points’ either side of the Arabian Peninsula and the Straits of Malacca are of equal or greater concern than export embargoes.

Up to the 1970s, oil supply was more naturally concentrated, even before considering the effect of OPEC. Today oil supply is less concentrated. In the 1970s, OPEC was in a dominant position, with very low cost oil and a near monopoly on exports. Today, OPEC retains a dominant position in oil exports, but is now subject to new infra-marginal competition from United States light tight oil.

Unexpected intentional supply disruptions are widely thought to have ‘caused’ the 1970s shocks’. However, as this paper indicates, the economic fundamentals show that the pressure was building before the shocks. The supply disruptions were the occasion that triggered the shocks. But the break point and need for rebalancing were inevitable. Since the 1970s, there have been no supply disruptions due to intentional sovereign actions. Disruptions due to technical and political external factors, wars and civil unrest are a ‘fact of life’ for the industry and are managed by the market. There are numerous examples of such disruptions from before the 1970s and since.

Both the 1970s first ‘oil shock’ and the recent high oil price period involved supply disruptions in the earlier ‘growth and dependency phase’ as well as at the ‘break point.’ In the latter case, the supply disruptions were larger in absolute terms and relative to global oil supply and global oil imports, than was the case in the 1970s. Nevertheless, in the recent examples, the market responded to rebalance supply and demand without IEA Emergency stock drawdowns or IEA collective action to make emergency stocks available. The examples from the 1970s predate the IEA.

Oil prices have been through a complete major price cycle since the price peaks (the break-point) of the 1970s. Current indications are that oil prices have recently entered the next major cycle. After adjusting for inflation, the average oil price level in 2011 was higher than the early 1970s, and the highest since 1864, (during the United States Civil War) before the internal combustion engine and when the market was just beginning to discover uses for oil from rocks. Real price levels are a good example of change, and also of continuity; the price cycle is not new. Oil prices are very sensitive to small short-term imbalances between supply and demand, and are likely to remain so.

Although real oil prices recently peaked above 1970s levels, global oil expenditure accounted for a much smaller share of global GDP than was the case in the 1970s: affordability is greater. This is due to two

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effects: proportionately reduced reliance on oil (and consequently increased reliance on other fuels, particularly natural gas and to a lesser extent coal) and higher levels of real GDP.

The presence of long price cycles is not the only constant from the 1970s. The categories of oil demand in the 1970s were very broad, including the power sector in many countries. While other sectors have dramatically reduced reliance on oil since the 1970s, the transport sector remains almost entirely dependent on oil, as it was in the 1970s and oil supply is heavily focused on meeting land, sea and air transport needs.

Alternatives and substitutes for oil were not well developed before 1973, but have accelerated since, including nuclear, coal and gas in the power sector, gas and electricity in industry. More recently, gas and electricity are beginning to find applications in the transport sector. A number of companies are developing and manufacturing battery electric vehicles, though they have yet to make significant progress in displacing fuel combustion transport.

General understanding of supplier power, buyer power, the role of market forces and ‘external factors’ was arguably less developed in the 1970s, particularly outside of academia in industry and policy circles. Evidence for this may be observed in the attempts of policy makers in the 1970s, notably in the United States, to fight market forces. Companies (most notably Shell) developed scenario planning in recognition of the limitations of earlier attempts to model the future. Academics developed entirely new types of structural models in response to the failure of regression techniques to project forward. Today these fields are much more highly developed and widely understood.

5.2. Concluding observations

This paper began with a quote from the IEA that:

‘Oil markets have changed enormously since the first oil shock of 1973-74.’

As this paper shows, since the 1970s, the oil market has been characterised by a number of step changes and transitions, as well as by continuous evolution. The profound changes in the oil market over the past four decades—as well as some factors that have continued unchanged—bring with them challenges for countries, policy-makers and international institutions. The challenges are particularly noticeable for the IEA and its member countries: the oil market today is very different from the oil market for which the IEA was designed.

OECD countries’ share of global oil imports is falling as their demand plateaus or declines and as oil demand grows in non-OECD countries. In the twenty-first century, oil demand is shifting inexorably eastwards, and is becoming focused in the Indo-Pacific region, led by growth in China, India and emerging Asia. China—which is the fifth-largest oil producer in the world—became oil import-dependent in 1993, and overtook the United States as the world’s largest oil importer in 2015. Because oil production in most countries in Asia falls short of consumption, oil trade flows are shifting eastwards even more strongly than is oil demand in general.

The reduction in United States oil imports due to domestic light tight oil production has further accelerated the eastward shift in oil imports. One consequence of all of these changes is that the approach to energy security can no longer be OECD-centric. Nor can it focus on the Euro-Atlantic region plus Japan, as was the case from 1974 to 2004. Oil markets have indeed changed enormously since the first oil shock of 1973-74, and will continue to change in the future.

Most of the changes in the oil market since the early- to mid-1970s have been beneficial: favourable for importing countries and consumers, and constructive for exporting countries and investors. Physical and financial oil markets are now large, deep and liquid. Market-based financial risk management is larger and more sophisticated than government initiatives intended to reduce risk. In the 1970s there was an oil industry but ‘the oil market’ as we know it today did not yet exist. The ‘first oil shock’ was small compared with more recent disruptions, but caused larger ‘ripples.’

The oil shocks of the 1970s were misdiagnosed and misunderstood at the time, as being caused by disruptions to supply external to the market and the economics of supply and demand, known as ‘exogenous supply shocks’ in the language of economics. However, economic research since 2000 has revealed that supply disruptions were the catalyst but not the cause of the shocks. The 1970s oil shocks

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were symptoms of economic problems. Real prices did not reflect the fundamentals of supply and demand, due to inadequacies in the mechanisms of price formation and price discovery. Exogenous oil supply disruptions explain no more than 20 per cent of the observed increase in the real price of oil in 1973-74. Shifts in the underlying demand for oil explain at least 80 per cent of the price changes. Speculative inventory demand (‘panic buying’) is observable before and during a number of oil crises, and can magnify the shock, but is not the underlying cause.

With the benefit of these recent insights, it is perhaps not surprising that government efforts in the 1970s failed to manage the oil market by emergency rationing. Historical data shows that oil supply disruptions of various magnitudes and durations in fact occur continually. There were nine material supply disruptions before the 1973-74 oil shock, five of which were greater than five per cent of oil imports to OECD countries, and there have been four disruptions since the 1978 Iranian revolution and the 1980 outbreak of the Iran-Iraq War (the second oil shock) greater than five per cent of oil imports to OECD countries.

Most oil supply disruptions are small and brief in duration. Some disruptions are small and of longer duration; others are large but relatively short. Large disruptions of long duration are rare, but do occur. Among the three cases of IEA collective action, only one was for a large disruption of long duration: 4.6 Mbpd of supply were disrupted for twelve months after Iraq’s invasion of Kuwait. History teaches us that the oil market actually manages supply disruptions effectively and efficiently. Allowing the market to work in the first instance is the most important oil policy.

Some of the policy responses in the 1970s worked against the market and hindered the effectiveness and efficiency of the market in rebalancing supply and demand. The clearest examples are price controls and allocations in the United States following the first oil shock and continuing through the second oil shock, and the focus on stock building during the second oil shock. Despite those policies, the market nonetheless managed to rebalance supply and demand, although the rebalancing process was no doubt prolonged, and probably contributed to the depth and duration of the subsequent oil price slump in the 1980s and 1990s. Underinvestment in that period sowed the seeds for the price surge that followed in the 2000s. This indicates that counter-market policies tend to exacerbate the natural cycle.

Notwithstanding the ongoing possibility of major disruptions arising from major geopolitical events, the risk of intentional or ‘strategic’ supply disruption by oil exporting countries is now much lower than in the past, because oil-exporting countries have learned from the long-term adverse effects of disrupting supply. All oil-exporting countries of significant size depend heavily on oil for export revenues, and for government revenues. That creates mutual inter-dependence and a natural alignment of between exporters and imports that reduces the risk of intentional supply disruption. Furthermore, oil has a smaller share of the fuel mix in the global economy than in the 1970s, so oil import dependence has been reduced, as has economic sensitivity to oil supply and prices. Unlike the 1970s, most electricity systems are now independent of oil.

The transport sector continues to be very heavily dependent on oil. However, at the same real price levels oil was more affordable in 2015 as 1975 because oil expenditure accounts for a much smaller proportion of GDP for the world as a whole. Australia spends a smaller share of its GDP on crude oil than does the world as a whole. Emerging economies do go through an oil-intensive phase of development in which oil demand grows more rapidly than GDP. China is a good example of this phenomenon, and India will likely follow the same pattern as its highway system is developed and the mobility of people and goods increases. Nevertheless, strong underlying trends of economic growth, changes in technology and countries’ fuel mix, and efficiency improvements mean that oil is expected to continue to remain, if not become more affordable in the future.

Whereas many of the oil and energy policies from the 1970s that worked against the market failed and were abandoned, other policies continued. A number of these policies were originally developed in response to the 1970s oil shocks, exist in parallel with the market, and are intended to complement it. They include energy efficiency initiatives, various forms of stockpiling, government collection and provision of oil market data, international cooperation and regular multilateral dialogue between energy ministers and industry executives.

The contemporary oil market is also far more transparent and supply is better at rebalancing than in the 1970s. Saudi Arabia has a near-monopoly on spare capacity and OPEC has a dominant market position in oil exports. Yet experience shows that in practice, those positions confer only limited pricing power, or only temporary power when the market is tight.

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Initial indications are that the United States shale oil revolution has resulted in an oil supply curve that may be able to respond more rapidly and more smoothly to price changes. Long-term indicators suggest the oil market is on the cusp of entering a new era. Although the price levels of 2015 and 2016 are not likely to be commercially sustainable for producers in the long-term, global pressures on new oil supply and prices have been eased by the United States shale revolution.

At the same time, the challenge for policy-makers, and for companies and investors, attempting to resolve the Energy Policy Trilemma, is arguably greater today than it has ever been. The goal of dramatically reducing carbon dioxide emissions to the extent that policy-makers have been advised is required, which goes well beyond the commitments in the 2015 Paris Accord, will clearly not be easy to achieve, and is one of only several completing policy priorities.

The physical and financial oil markets have evolved to become the world’s largest and most efficient international commodity market. This is made more remarkable by the fact that security of supply has also improved as a result of financial risk management becoming seamlessly integrated with short-run price discovery, commercial management of inventories and long-run investment decision-making.

5.3. Avenues for policy development and modernisation

Oil and the global macro economy are deeply interwoven, as are markets and economy-energy-environment (‘3E’) policy settings. The IEA Ministers’ Communiqué in 1993 stated that they ‘believe that global economic development, energy security and environmental protection will be enhanced if all nations of the world subscribe to the goals which the IEA countries share.’ These ‘Three Es’ of energy policy provide the base for the IEA Shared Goals.17

More than 20 years later, although priorities and constraints change and also vary between countries, affordability, security and environmental sustainability are still the three major goals of energy policy throughout the world. Reducing carbon dioxide beyond the commitments in the 2015 Paris Accord, presents significant policy challenges. The experience gained during the third and fourth decades of the IEA’s history (1994-2014) shows that economic growth and the free market have not only delivered increased affordability, but oil security has also improved. This provides encouragement that the free market principles set out in the IEA’s Shared Goals of 1993 can also provide a solid foundation for the goals of the IEA Modernisation Programme, as announced in 2015.18

There are a number of avenues for cooperative research, policy development and collaboration between and beyond IEA member countries. A deeper understanding of the historical relationship between the magnitude, duration and frequency of oil supply disruptions would be very valuable for many stakeholders. The contribution of markets to strengthening and broadening oil and energy security since the 1980s could be better understood. That could include quantifying the extent to which risk management by the market has relieved the pressure on official oil security emergency response systems. The global economic benefit resulting from the continual operation of risk management through the financial markets in oil futures and derivatives has not yet been studied, to the authors’ knowledge. Furthermore, it would be beneficial to review how the emergency oil reserves system could be modernised to complement and work seamlessly with the existing large and sophisticated financial oil markets.

17 Scott R (1995) IEA—The First 20 Years: The History of the International Energy Agency 1974-1994; Volume Two: Major Policies and

Actions, IEA and OECD, Paris, p224.

18 Moniz E J (2015), Summary of the Chair, IEA Ministerial Meeting, 17-18 November 2015

https://www.iea.org/media/news/2015/press/IEAMinisterialChairsSummary.pdf

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Chapter 6. Appendices

6.1. Major historical oil supply disruptions and recent international trade flows

6.1.1. Oil supply disruptions since 1950

Table 13 List of oil supply disruptions and instances of IEA Collective Action, 1950-2015

# Description Cause of Disruption State Date Length Gross shortfall IEA *

imports

category months MMbpd % MMbpd

1 Iranian Fields Nationalized Embargo/Econ Disp 1 Mar 1951 44.7 0.7

2 Suez War Mideast War 1 Nov 1956 5.0 2.0

3 Syrian Transit Fee Dispute Embargo/Econ Disp 1 Dec 1966 4.0 0.7 5% 13.6

4 Six Day War Mideast War 1 Jun 1967 3.1 2.0 14% 14.6

5 Nigerian Civil War Internal Struggle 1 Jul 1967 16.3 0.5 3% 14.6

6 Libyan Price Controversy Embargo/Econ Disp 1 May 1970 9.2 1.3 6% 20.4

7 Algerian-French Nat'l Struggle Internal Struggle 1 Apr 1971 5.1 0.6 3% 22.1

8 Lebanese Political Conflict Internal Struggle 1 Mar 1973 3.1 0.5 2% 27.4

9 October Arab-Israeli War Mideast War & Embargo/Econ 1 Oct 1973 6.1 1.6 6% 27.4

10 Civil War in Lebanon Internal Struggle 1 Apr 1976 2.0 0.3 1% 27.7

11 Damage at Saudi Oilfield Accident 1 May 1977 1.0 0.7 2% 28.1

12 Iranian Revolution Internal Struggle 1 Jan 1978 6.0 3.7 13% 28.8

13 Outbreak of Iran-Iraq War Mideast War 1 Oct 1980 4.1 3.0 12% 25.4

14 UK Piper Alpha Offsh. Plat. Expl Accident 1 Jul 1988 17.3 0.3 1% 24.8

15 UK Fulmer Float. Stor. Vess. Acc Accident 1 Dec 1988 4.0 0.2 1% 24.8

16 Exxon Valdez Accident Accident 24 Mar 1989 0.5 1.0 4% 25.8

17 UK Cormorant Offshore Platform Accident 1 Apr 1989 3.0 0.5 2% 25.8

18 Iraq-Kuwait War Mideast War 1 Aug 1990 12.0 4.6 18% 26.2 Y

19 Unilateral Embargo on Iran Embargo/Econ Disp 1 Aug 1995 1.0 0.2 1% 29.8

20 Norwegian Oil Workers Strike Internal Struggle 1 May 1996 1.0 1.0 3% 30.8

21 Local Protests in Nigeria Internal Struggle 1 Mar 1997 1.0 0.2 1% 31.5

22 Local Protests in Nigeria Internal Struggle 1 Mar 1998 3.0 0.3 1% 31.8

23 OPEC (ex. Iraq) cuts production Embargo/Econ Disp 1 Apr 1999 12.0 3.3 10% 33.0

24 Venezuelan Oil Strike Internal Struggle 2 Dec 2002 2.5 2.0 6% 33.0

25 Iraq War Mideast War 19 Mar 2003 1.4 1.9 6% 33.9

26 Hurricane Katrina Natural disaster 28 Aug 2005 2.5 0.6 <2% 35.2 Y

27 Hurricane Rita Natural disaster 24 Sep 2005

28 United States Macondo blowout Accident 20 Apr 2010 5.0 <0.1 0% 31.6

29 Libyan Revolution Internal Struggle 15 Feb 2011 8.3 1.2 4% 30.9 Y

Sources: Beccue and Huntington (2005) Table E.1, p.55, up to Iraq War. Author’s research from 2005. Notes: * Annual rate in year disruption began “Y” in the last column indicates an IEA collective action Hurricane Katrina formed on 23rd August, made landfall on 25th August, strengthened and made second landfall on 29th August, and dissipated on 31st August. Hurricane Rita formed on 18th September, made landfall on 24th September and dissipated on 26th September. “Hurricanes Katrina and Rita shut down oil and gas production from the Outer Continental Shelf in the Gulf of Mexico, the source for 25 per cent of U.S. crude oil production and 20 per cent of natural gas output. Katrina, which made landfall on August 29, resulted in the shutdown of most crude oil and natural gas production in the Gulf of Mexico, as well as a great deal of refining capacity in Louisiana and Alabama, 554,000 barrels per day of which was still closed as of late October, 2005. (Kumins and Bamberger, 2005)

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6.1.2. The 1973 oil crisis: a chronology of selected events

The following is adapted from the chronology publicly available on several Wikipedia pages, including ‘Chronology of world oil market events,’80 covering the period 1970-97, and draws on information in Yergin (1991), with additions and edits on the author’s research and cross-checking.

• June 5-10, 1967—Six Day War (also known as the June War, 1967 Arab-Israeli War, or Third Arab-Israeli War) between Israel, Egypt, Jordan and Syria, resulting in the Israeli capture of the Sinai Peninsula and the Gaza strip from Egypt, the West Bank from Jordan and the Golan Heights from Syria.

• 1970—oil production in the United States peaks at 11.3 Mbpd, while spare capacity shrinks to 1 Mbpd, compared with about 4 Mbpd between 1957 and 1963 (Yergin, 1991, p.567) Oil production would not again reach the level of 1970 until 2014, after the bottom of 6.8 Mbpd in 2008.

• September 4 to October 9—Libya raises posted prices and increases the tax rate from 50 to 55 per cent. Iran and Kuwait follow in November.

• January 12, 1971—negotiations over posted prices begin in Tehran between 6 OPEC Persian Gulf states and 22 oil companies.

• February 3, 1971—OPEC mandates "total embargo" against any company that rejects 55 percent tax rate.

• February 14, 1971—Tehran Price Agreement signed: oil companies accept 55 percent tax rate, immediate increase in posted prices, and further successive increases.

• February 24, 1971—Algeria nationalizes 51 percent of French oil concessions.

• March 1971—‘for the first time in a quarter century, the Texas Railroad Commission allowed…production at 100 percent of capacity. “We feel this to be an historic occasion,” declared the chairman of the commission. “Damned historic, and a sad one. Texas oil fields have been like a reliable old warrior that could rise to the task when needed. That old warrior can’t rise anymore.”

• August 15, 1971—the United States unilaterally withdraws from the Bretton Woods Accord, by abandoning the Gold Exchange Standard under which the value of the US dollar had been pegged to the price of gold and all other currencies were pegged to the dollar.

• August 15, 1971—the US Government institutes Phase I price controls. Invoking the powers granted to the president by the Economic Stabilization Act of 1970, President Richard Nixon orders 90-day nationwide freeze on all wages, prices, salaries and rents.

• September 22, 1971— OPEC directs members to negotiate price increases to offset the dollar devaluation.

• January 1973—The 1973-74 stock market crash commences as a result of inflation pressure and the collapsing monetary system.

• June 1, 1972— Iraq nationalizes Iraq Petroleum Company's (IPC) concession owned by British Petroleum, Royal Dutch-Shell, Compagnie Francaise des Petroles, Mobil and Standard Oil of New Jersey (now Exxon). The concessions were valued at over one billion dollars.

• April, 18, 1973—Nixon abolishes the Mandatory Oil Import Quota Program and in its place establishes a license-

fee quota system to allocate imports, which also imposed tariffs.16

• August 23, 1973—In preparation for the Yom Kippur War, Egyptian president Anwar Sadat travels to Riyadh, meets with Saudi King Faisal and secretly negotiates an accord whereby the Arab nations will use the ‘oil weapon’ as part of the military conflict (Yergin, 1991, p.597)

• October 6—Egypt and Syria launch a surprise attack on Israeli-occupied lands in the Sinai Peninsula and Golan Heights on the Yom Kippur religious holiday, starting the 1973 Arab-Israeli War.

• Night of October 8—Israel goes on full nuclear alert. US National Security Advisor Henry Kissinger is notified on the morning of October 9. The United States begins to resupply Israel.

• October 8–10—OPEC negotiations with major oil companies to revise the 1971 Tehran price agreement fail.

• October 12—The United States initiates Operation Nickel Grass, a strategic airlift to provide replacement weapons and supplies to Israel. This followed similar Soviet moves to supply the Arab side.

• October 14—in Vienna OPEC announced the failure of its oil price negotiations with the companies

• October 16—delegates of Saudi Arabia, Iran, Iraq, Abu Dhabi, Kuwait and Qatar met in Kuwait City and announced their decision to raise the posted price of oil by 70 percent to $5.11 per barrel. (Yergin, p.606)

• October 17—OAPEC oil ministers agree to use oil to influence the West's support of Israel. They recommended an embargo against non-complying states and mandated export cuts.

• October 19—Nixon requests Congress to appropriate $2.2 billion in emergency aid to Israel, which triggers a collective Arab response (Lenczowski, 1990). Libya immediately proclaims an embargo on oil exports to the US and Saudi Arabia and other Arab oil-producing states follow the next day. (United States State Department Archive, 2008)

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• October 26—The Yom Kippur War ends.

• November 2— Emergency Petroleum Allocation Act (EPAA) introduced in the United States Senate.

• November 5—Arab producers announce a 25 per cent output cut. A further 5 per cent cut is threatened.

• November 9: EPAA passes the United States Senate.

• November 13: EPAA passes the United States House of Representatives.

• November 23—The Arab embargo is extended to Portugal, Rhodesia and South Africa.

• November 27—United States President Nixon signs the Emergency Petroleum Allocation Act (EPAA) authorizing price, production, allocation and marketing controls.

• December 9—Arab oil ministers agree to another five percent production cut for non-friendly countries in January 1974.

• December 25—Arab oil ministers cancel the January output cut. Saudi oil minister Ahmed Zaki Yamani promises a ten percent OPEC production rise.

• January 7–9, 1974—OPEC decides to freeze prices until April 1.

• January 18—Israel signs a withdrawal agreement to pull back to the east side of the Suez Canal.

• February 11—Henry Kissinger unveils the ‘Project Independence’ plan for United States energy independence.

• February 12–14—Progress in Arab-Israeli disengagement triggers discussion of oil strategy among the heads of state of Algeria, Egypt, Syria and Saudi Arabia.

• March 5—Israel withdraws the last of its troops from the west side of the Suez Canal.

• March 17—Arab oil ministers, with the exception of Libya, announce the end of the United States embargo.

• May 31—Diplomacy by Kissinger produces a disengagement agreement on the Syrian front.

• November 18, 1974—foundation of the IEA via an Agreement on an International Energy Program, signed on behalf of the initial sixteen Member states: Austria, Belgium, Canada, Denmark, Germany, Ireland, Italy, Japan, Luxembourg, The Netherlands, Spain, Sweden, Switzerland, Turkey, United Kingdom, and the United States. Norway also participates in the Agency under a special Agreement since 1974.

• December 1974—The 1973–74 stock market crash ends.

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6.1.3. Crude oil and refined product trade flows

Table 14 Summary of crude oil and refined product trade flows, million tonnes, 2015

Crude oil

To Americas EU-Rus-CIS Middle East Africa Asia-Pacific

SUBTOTALS

From

Americas 294 32 < < 90 416

EU-Rus-CIS 7 240 7 2 90 346

Middle East 83 108 - 13 675 880

Africa 31 134 < - 120 285

Asia-Pacific 3 < < < 47 50

SUBTOTALS 419 514 8 15 1 021 1 977

Refined liquid products

To Americas EU-Rus-CIS Middle East Africa Asia-Pacific

SUBTOTALS

From

Americas 168 39 2 7 49 265

EU-Rus-CIS 54 110 17 46 64 291

Middle East 3 24 - 16 99 141

Africa 11 8 1 - 7 27

Asia-Pacific 20 17 17 14 236 304

SUBTOTALS 256 199 37 83 454 1 029

Total crude oil plus refined products

To Americas EU-Rus-CIS Middle East Africa Asia-Pacific

SUBTOTALS

From

Americas 463 71 2 7 139 681

EU-Rus-CIS 61 351 24 48 153 637

Middle East 86 132 - 29 774 1 021

Africa 42 142 1 - 127 312

Asia-Pacific 23 17 17 14 282 355

SUBTOTALS 675 713 45 98 1 476 3 006

Source: BP, Statistical Review of World Energy, 2016. < means less than 1; - means zero

6.2. International organisations

OPEC—the Organisation of Petroleum Exporting Countries—describes itself as ‘a permanent intergovernmental organization of 14 oil-exporting developing nations that coordinates and unifies the petroleum policies of its Member Countries.’81 OPEC was created at the Baghdad Conference on September 10–14, 1960, by Iran, Iraq, Kuwait, Saudi Arabia and Venezuela. The five Founding Members were later joined by nine other Members: Qatar (1961); Indonesia (1962); Libya (1962); United Arab Emirates (1967); Algeria (1969); Nigeria (1971); Ecuador (1973); Angola (2007); and Gabon (1975). Indonesia suspended its membership from January 2009 to December 2015. Ecuador suspended its membership from December 1992-October 2007. Gabon terminated its membership in January 1995 but rejoined in July 2016. OPEC had its headquarters in Geneva, Switzerland, in the first five years of its existence. This was moved to Vienna, Austria, on September 1, 1965.82

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OECD—the Organisation for Economic Cooperation and Development—exists to promote policies that will improve the economic and social well-being of people around the world. The organisation was founded in 1961, is headquartered in Paris and counts 35 countries as members.

IEA—the International Energy Agency—is an autonomous organisation which works to ensure reliable, affordable and clean energy for its 29 member countries and beyond. The IEA has four main areas of focus: energy security, economic development, environmental awareness and engagement worldwide. The IEA was founded in 1974 as an agency of the OECD under a treaty known as the International Energy Partnership to help countries co-ordinate a collective response to major disruptions in the supply of oil. While this remains a key aspect of its work, the IEA has evolved and expanded. It is at the heart of global dialogue on energy, providing authoritative statistics and analysis. Membership is currently restricted to OECD members, although not all OECD countries are currently IEA members. OECD members Chile and Mexico are candidate countries for accession to the IEA. Directed by its member countries, the IEA has developed close co-operative working relationships with major emerging economies such as Brazil, China, India, Mexico, Russia and South Africa. In 2016, China, Indonesia and Thailand activated Association status with the IEA. The Agency also works extensively with other countries in the Black Sea and Caspian regions as well as the Middle East and North Africa.83

United States DoE—the United States Department of Energy—was established in 1977 as a Cabinet-level department of the United States government concerned with the United States policies regarding energy. The DoE is also responsible for safety in the handling of nuclear material.

EIA—the Energy Information Administration—was established in 1978 with statutory independence from the government to collect, analyse, and disseminate independent and impartial energy information to promote sound policymaking, efficient markets, and public understanding of energy and its interaction with the economy and the environment.

APEC—the Asia-Pacific Economic Cooperation forum—is a regional economic forum established in 1989 to leverage the growing interdependence of the Asia-Pacific. APEC’s 21 members aim to create greater prosperity for the people of the region by promoting balanced, inclusive, sustainable, innovative and secure growth and by accelerating regional economic integration. APEC members who are also IEA members include Australia, Canada, Japan, New Zealand and the United States. IEA candidates Mexico and Chile are also APEC members.

APERC—the Asia Pacific Energy Research Centre—was established in July 1996 in Tokyo following the directive of APEC Economic Leaders in the Osaka Action Agenda. APERC is co-located with the Institute for Energy Economics, Japan (IEEJ). The primary objective of APERC is to conduct research to foster understanding among APEC members of the regional energy outlook, market developments and policy.

IEF—the International Energy Forum—which was formed after the first meeting in Paris in 1991, aims to foster greater mutual understanding and awareness of common energy interests among its members. It has 73 member countries covering all six continents and accounting for around 90 per cent of global supply and demand for oil and gas. The member countries are signatories to the IEF Charter outlining the framework of the global energy dialogue. The permanent Secretariat of international staff are based in the diplomatic quarter of Riyadh in Saudi Arabia.

JODI—the Joint Organisations Data Initiative—was originally established as in 2001 under the auspices of the IEF by APEC, Eurostat, the IEA, OLADE, OPEC and the UNSD launched the Joint Oil Data Exercise, which broadened within a year to cover 90 per cent of oil supply and demand and became the Joint Oil Data Initiative. Now the Joint Organizations Data Initiative, JODI publishes world databases for oil and gas.

WEC—the World Energy Council—formed in 1923, is the UN-accredited global energy body, representing the entire energy spectrum, with more than 3000 member organisations located in over 90 countries and drawn from governments, private and state corporations, academia, NGOs and energy-related stakeholders. The World Energy Council informs global, regional and national energy strategies by hosting high-level events, publishing authoritative studies, and working through its extensive member network to facilitate the world’s energy policy dialogue.

The WTO is not involved in the international energy sector, as explained by the World Trade Institute:

‘…the rules of the General Agreement on Tariffs and Trade (GATT), and now the World Trade Organization (WTO), do not deal with energy as a distinct sector. It was felt that general rules, including the disciplines on

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state trading, could adequately address trade in energy. However, certain features of the energy sector make it different from other industries in many ways and we submit existing WTO rules do not appropriately address all the needs of energy trade today. Ensuring security of supply and addressing climate change mitigation, creating an effective incentives mechanism to reduce CO2 emissions are the first priorities.84

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Endnotes to the text

i International Energy Agency, Energy Supply Security, 2014, p.20 2 The “seven sisters” group comprised Anglo-Persian Oil Company (now BP); Gulf Oil, Standard Oil of California (now Chevron), Texaco (later merged with Chevron); Royal Dutch Shell; Standard Oil of New Jersey (Esso/Exxon) and Standard Oil Company of New York (Socony) (trading as Mobil now part of ExxonMobil). 3 The Embargo was imposed on Canada, Japan, the Netherlands, the United Kingdom, and the United States, and later extended to include Portugal, Rhodesia and South Africa. 4 Meyer, G (2012) ’US to adopt Brent as oil reference price EIA to switch from WTI in its annual energy outlook’, Financial Times, December 7th 5 Note that the eras shown in Figure 3 are adapted from the work of Luciani (2010), as in Table 1. The author of the present paper found that the pattern discovered in earlier research on oil and gold prices aligned strongly with Luciani’s work on oil pricing regimes. 6 See for example, Professor Jeffrey Frankel (2013) of Harvard University, who makes the case in a draft Energy Brief for the influential and non-partisan Council on Foreign Relations that ‘National security warrants slowing domestic oil depletion, not accelerating it,’ in the words of the paper’s title. 7 Unlike the oil sector, it has not historically been the practice of the gas sector to maintain strategic stocks. Europe has very little strategic gas storage. Prior to the 2006 crisis, only Italy had strategic gas storage. European countries and gas companies did not build new strategic storage or require companies to hold strategic stocks in response to the gas supply disruptions. The main exception was Hungary (Ref4e, Mercados, E-Bridge, 2015), whose parliament passed a strategic storage Act (Act Nº XXVI of 2006). 8 BP, Statistical Review of World Energy, June, 2016. 9 Australia has a very small population of about 23 million people scattered around the coasts of a continental-scale landmass. With 7.74 million sq. km, Australia is the sixth largest country in the world by area. The urbanization rate is high: almost 90 per cent. The distance by road from Sydney to Perth is almost 4000 km, and the road distance from Melbourne via Sydney to Brisbane (the corridor that contains more than 60 per cent of the population) is about 1800 km. 10 There are examples of non-OPEC oil exporters where oil revenue is a large share of exports. Examples include the IEA countries Norway (where oil and gas were 30 and 29 per cent of exports in 2014) and Canada (where oil, gas and refined products were 26 per cent of exports in 2014). In Australia, iron ore (25 per cent), thermal and coking coal (15 per cent) and LNG (6.7 per cent) were the three largest sources of export income in 2014. Australia’s oil exports were only 3.7 per cent of all exports, and it was a net importer of oil and refined products. 11 The US was a net exporter of crude oil from 1933 to 1943, with the exception of 1940 and 1941, when it was a net importer. The US has been a net importer of crude oil since 1944, when in imported 28 kbpd. The US was also a small net importer of crude oil from 1910 to 1915 and from 1920 to 1932. In other years it was self-sufficient, with zero net imports. 12 For the sake of comparison with the rapid drafting and passage of the EPAA, the EPCA took 318 days from its introduction to the Senate on February 7th, 1975 to signature by President Ford on December 22nd, 1975. In addition to establishing the SPR, the EPCA established the Energy Conservation Program for Consumer Products and the Corporate Average Fuel Economy (CAFÉ) regulations. 13 ‘…in 1975, Congress enacted Section 103 of the Energy Policy and Conservation Act (EPCA), 42 U.S.C. §6212, which required the President to implement regulations to prohibit the “export of crude oil . . . produced in the United States.” The ban applied to all U.S. crude oil with the exception of a few narrow categories (e.g., exports to Canada). In addition to the EPCA, several other statutes established restrictions on the export of more specific classes of crude oil based upon the location where the commodity was produced. The regulations implementing the export restrictions on crude oil are codified in the Export Administration Regulations at 15 C.F.R. §754.2. In contrast to the broad crude oil export ban, most domestically refined petroleum products are not generally subject to restrictions and may be exported without federal authorization.’ (Botts, 2015) 14 ‘All crude oil and refined petroleum products are exempted from the price and allocation controls adopted pursuant to the Emergency Petroleum Allocation Act of 1973, as amended. The Secretary of Energy shall promptly take such action as is necessary to revoke the price and allocation regulations made unnecessary by this Order.’ Executive Order 12287 is available at: http://www.presidency.ucsb.edu/ws/?pid=43901 15 The US ban on crude oil exports was repealed through the Consolidated Appropriations Act of 2016 (the ‘2016 omnibus spending bill’) signed into law by President Obama on 18th December 2015. 16 ‘Effective today, I am removing by proclamation [4210] all existing tariffs on imported crude oil and products. Holders of import licenses will be able to import petroleum duty free. This action will help hold down the cost of energy to the American consumer. Effective today, I am also suspending direct control over the quantity of crude oil and refined products which can be imported. In place of these controls, I am substituting a license-fee quota system. Under the new system, present holders of import licenses may import petroleum exempt from fees up to the level of their 1973 quota allocations. For imports in excess of the 1973 level, a fee must be paid by the importer.’ (Nixon, 1973)

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17 OPEC reserves need to be interpreted with a degree of caution. Initial production quotas for the group were based on reserve estimates and there is evidence to suggest these were inflated to secure favorable quotas. Furthermore, reserve estimates published by OPEC members have not changed dramatically in the period, despite continued production and relatively low levels of capital investment. 18 There are various methods for estimating oil reserves, and the responsible organisation in each country has its own set of classifications and definitions for reporting oil reserves. Etherington, Pollen, and Zuccolo (2005) reviewed the classifications and definitions published in the US, UK, Canada, Russia, China, Norway, and by the UN, as used in securities regulations, government reporting and companies’ internal resource and asset management. “All the major classifications define 3 major categories: undiscovered, discovered sub-commercial and discovered commercial” (table 1, p.9). In all cases, the word ‘reserves’ is applied to discovered commercial reserves, which involves the application of an economic or commercial test. 19 Fullenbaum and Curtis (2015), p.116 20 Former Soviet Republics that are now members of the Commonwealth of Independent States contributed somewhat to the former USSR total production, but Russia was the main producer. 21 The low cost of pipeline and tanker transport for oil contrasts with natural gas, which is proportionately very expensive to transport over long distances. The density of gas needs to be artificially increased for its transport, either by compression to high pressures for pipeline transport, or by liquefying to very low temperatures for shipping. 22 BP, Statistical Review of World Energy, 2016 23 Most of this is from Canada, and Mexico to the US in North America. 24 China (17 per cent), India (10 per cent) and Japan (8.5 per cent) between them account for 35 per cent of global crude oil imports. 25 India (5.3 per cent), China (3.6 per cent) and Japan (1.7 per cent) account for more than 10 per cent of global refined product exports. 26 Singapore accounts for another 8.6 per cent, bringing the total to 19.6 per cent of global refined product exports. Singapore alone imports over 12.2 per cent of global refined product trade, in addition to 2.3 per cent of internationally traded crude oil. The difference between Singapore’s imports and exports is accounted for largely by the shipping industry re-fuelling. 27 Crude oil prices influence natural gas prices through contract price linkages (e.g. in traditional Asian LNG contracts) and indirectly through competition between gas and oil products. Condensate markets also link oil and natural gas markets, as condensates co-produced in ‘wet’ natural gas fields can be ‘spiked’ into crude oil lines and sent to refineries. 28 McKay (2013) provides an insightful discussion and analysis of the role of the US dollar as an international vehicle currency in the context of Japan’s unrealized ambitions in the 1990s to become a first tier international financial centre and Shanghai’s aspirations. Local money that serves as an international vehicle currency is one of ten critical features of first tier international financial centres. McKay defines an international vehicle currency as ‘[a] convertible, internationalized currency that is acceptable as a store of value, unit of account, a denominator for unrelated third party real economy and financial transactions (especially debt) and is readily able to be hedged in liquid markets.’ 29 The BP Statistical Review of World Energy, 2016 shows 88.834 million barrels of liquids, which ‘includes crude oil, shale oil, oil sands and NGLs (natural gas liquids—the liquid content of natural gas where this is recovered separately)’ for 2014, and 91.670 in 2015. Natural gas production is shown as 335.1 bcf per day in 2014 and 342.4 in 2015. Using the standard conversion factor of 5800 standard cubic feet of gas as equivalent to one barrel of oil, means world gas production was equivalent to 57.771 Mbpd of oil in 2014 and 59.030 in 2015. 30 The volumes represent working interest production before royalties, in barrels of oil and natural gas equivalents. The data are from Wood Mackenzie and published by Forbes. http://www.forbes.com/sites/christopherhelman/2015/03/19/the-worlds-biggest-oil-and-gas-companies/#75692b126b68 accessed 5 September 2016. 31 Russia accounts for the majority of oil production and exports from CIS countries. The CIS total is shown here for consistency with the earlier data for the USSR, the Russian part of which is not available. 32 OPEC/ About us: Our Mission http://www.opec.org/opec_web/en/about_us/23.htm accessed 22nd August 2016 33 HHI is the classic measure of market concentration. It is calculated as the sum of the squares of market shares. So, for example, the HHI for a market with four competitors, each with an equal 25 per cent share of the market, would be 0.25. A market with four competitors with 40, 30, 20 and 10 per cent shares would be 0.30—indicating higher market concentration than in the case of equal shares. A monopoly has an HHI of 1. A duopoly has an HHI of between 0.5 and 1, depending on the shares, and a market with 100 competitors each with a 1 per cent share has an HHI of 0.01. An HHI of 0.25 is considered to be a concentrated market, or oligopoly. An HHI of 0.15 is considered to be an unconcentrated market. 34 A cartel is defined as ‘an association of manufacturers or suppliers formed to keep prices high and restrict competition.’ (Oxford Dictionary of Economics). Today most nations have laws against private cartels. Examples of early competition law can be found in 15th century English common law, in the Middle Ages and in Roman law. Interestingly, the first major landmark in competition law in modern times was the Sherman Antitrust Act of 1890, which was targeted at the Standard Oil Trust in the United States.

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However, OPEC is an international cartel and a public cartel, as it was formed with the involvement of governments. This distinction means that OPEC is in an entirely different category from domestic cartels and private cartels, because the governments’ sovereignty shields OPEC from legal actions. International trade is a matter for the World Trade Organisation (WTO). The predecessor of the WTO, the General Agreement on Tariffs and Trade (GATT) came into force at the beginning of 1948 (World Trade Organisation, 1986). Cottier et al (2010) write on the subject of energy and international trade law in an article for the 2010 World Trade Report of the WTO:

International trade in energy resources and products traditionally was heavily concentrated, cartelised and controlled by a few multinational companies. Hence the rules of the General Agreement on Tariffs and Trade (GATT), and now the World Trade Organization (WTO), do not deal with energy as a distinct sector. It was felt that general rules, including the disciplines on state trading, could adequately address trade in energy.

The WTO authors also implicitly acknowledge that OPEC’s incentive to restrict production, and sustain oil prices at levels higher than they would be in a competitive market are consistent with efforts to reduce fossil fuel use to limit carbon dioxide emissions:

However, certain features of the energy sector make it different from other industries in many ways and we submit existing WTO rules do not appropriately address all the needs of energy trade today. Ensuring security of supply and addressing climate change mitigation, creating an effective incentives mechanism to reduce CO2 emissions are the first priorities.

For this, and other reasons, as the WTO article puts it: Doctrines of multilayered governance have hardly been applied to the sector.

During World War 2, the American and British governments became concerned that the abundance of oil in the Middle East meant that ‘…the problem from a global point of view would be too much oil—and how to control production.’ An Anglo-American Petroleum Agreement, signed on August 8th 1944 failed to gain the support of the independent US oil producers, key members of Congress or the oil majors, and was withdrawn before it became law (Yergin, 1991, pp.401-3). In 1949, the US Federal Trade Commission tried to launch an antitrust case against American and foreign oil companies. Their report (FTC, 1952) was (ironically) released through Subcommittee on Monopoly of Select Committee on Small Business. President Truman called off the criminal investigation. It was replaced by a civil action filed under the incoming Eisenhower administration. Yergin, (1991, pp.472-5) neatly summarises this episode in antitrust history. ‘The only reason that the Justice Department had not gone ahead with the criminal case was, as L. J. Emmerglick, a senior antitrust attorney, put it, “the considered judgment of two Presidents, two Secretaries of State or their principal representatives, two Secretaries of Defence, and in addition, the Chairman of the Joint Chiefs of Staff, the Central Intelligence Agency, and a number of present and former Cabinet members.’ 35 BP, Statistical Review of World Energy, 2016 36 According to the field of economics known as game theory, cartels are inherently unstable because each member of a cartel could increase its profit by breaking the agreement compared with its profit level while in compliance with the agreement. However, if all members break the agreement by producing more or selling at a lower price than agreed, all would be worse off. In the case of OPEC, the influence of the short-run incentive to over-produce (or undercut on price, or both) has tended to be finely balanced with the long-run incentive not to see the cartel break down completely. 37 The IMF calculates and publishes estimates of oil exporting countries’ fiscal break-even price and the external break-even price. See, for example IMF (2016b) 38 Levin et al (2016). The standard error (s.e.) on the elasticity estimate of -0.323 based on city level daily data is 0.025. The elasticity estimate is from a Log-Log model: Dependent Variable = ln(quantity per capita) using Pay-at-Pump VISA card data (i.e. not including non-gasoline convenience purchases made at the same time). The elasticity

estimates for the same data when aggregated are as follows: state daily data ‑ 0.245 (s.e. 0.059); national daily data

‑ 0.014 (0.067); city monthly data ‑ 0.246 (0.028); state monthly data ‑ 0.215 (0.066); national monthly data ‑ 0.002 (0.021). Hence the authors’ conclusion that price elasticity at the national level are “indistinguishable from zero.” 39 The IEA’s World Energy Outlook publications are reviewed by and benefit from the comments and contributions of a very large panel of technical and economic experts from leading companies as well as academic and research institutes around the world. 40 Influential national institutions include:

the United States Department of Energy (DoE)

the Energy Information Administration (EIA) in the United States

the Institute for Energy Economics Japan (IEEJ)

the Energy Research Institute (ERI) of

the National Energy Administration (NEA) of

the National Development and Reform Commission (NDRC) in China The IEEJ is the host organisation for the Asia Pacific Energy Research Centre (APERC), which reports to APEC members and to the APEC Secretariat in Singapore. 41 ‘Our price is too high in relation to the world market,’ was the summary of Saudi Arabia’s Oil Minister Sheik Yamani at the OPEC meeting in 1983’ Yergin (1991), p.720.

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42 Adding the former Soviet republics of Azerbaijan, Kazakhstan, Turkmenistan and Uzbekistan only brought the total to 7.2 Mbpd. 43 Note that the corresponding IEA data (which begin in 1971 and at the time of writing ended in 2013) includes non-commercial energy (primarily biomass such as firewood and dung in developing countries), which increases the non-fossil fuel share, makes the denominator larger and accordingly reduces the percentage shares for oil, coal and gas. 44 In February 1965 the French President Charles de Gaulle announced his intention to exchange its US dollar reserves for gold at the official exchange rate (de Vries, 1976). ‘In 1966, foreign central banks and governments held over 14 billion U.S. dollars. The United States had $13.2 billion in gold reserves, but only $3.2 billion of that was available to cover foreign dollar holdings. The rest was needed to cover domestic holdings. If governments and foreign central banks tried to convert even a quarter of their holdings at one time, the United States would not be able to honor its obligations’ (IMF, undated) 45 The US-led invasion was called ‘Operation Iraqi Freedom’ by the US, and was conducted in coalition with the United Kingdom, Australia, Poland and Spain. 46 Some ‘102 North American oil and gas producers that have filed for bankruptcy since the beginning of 2015. These bankruptcies, including Chapter 7, Chapter 11, Chapter 15, and Canadian cases, involve approximately $67.8 billion in cumulative secured and unsecured debt. As of September 7, 2016, 58 producers have filed bankruptcy so far this year, representing approximately $50.4 billion in cumulative secured and unsecured debt. Despite the recent spike in oil prices, all indications suggest more producer bankruptcy filings will occur during 2016.’ (Haynes and Boone, 2016) 47 ‘[E]nergy efficiency improvements for a group of 11 IEA countries (IEA11) averaged 2 per cent per year between 1973 and 1990.’ Oil price increases were a major stimulus for these improvements. The rate of improvement slowed in subsequent decades, after prices had come down. ‘Between 1990 and 2005, the overall improvement in energy efficiency in all end-use sectors of the economy for the IEA16 was 0.9 per cent per year.’ (IEA, 2008b) 48 www.kockw.com/sites/EN/Pages/Profile/History/OilFires.aspx 49 www.bechtel.com/projects/kuwait-reconstruction/ 50 The SPR holds emergency reserves in four underground salt caverns in Texas and Louisiana. 51 www.iea.org/netimports/ 52 OECD (1974) Agreement on an International Energy Program (As amended 9 May 2014), Paris. 53 Following Iraq’s invasion of Kuwait, ‘Australian and state/territory governments activated the preliminary arrangements that had been put in place in accordance with the Liquid Fuels Emergency Act (1984). The National Oil Supplies Emergency Committee was the main intergovernmental forum for consultation on situation assessment and met at least once a week to discuss the process as well as share briefings.’ The 1984 Act provides for the Minister responsible for oil in the Federal Government to declare a liquid fuels emergency, and empowers the Minister to implement arrangements for the allocation of wholesale product supplies while emergency arrangements are in place. There was no need to declare an emergency under the Act in 1990-91, and as of October 2016, such an emergency has never been declared in Australia. 54 The earlier studies focused on the commodity price index (Roll, 1972), Rotterdam oil spot prices (Gjolberg, 1985), the Rotterdam and Italian oil markets (Panas, 1991), and the US spot and futures markets for natural gas (Herbert and Kreil, 1996). Among the later literature, some researchers find inefficiency, while others find efficiency. The overall trend in the literature is of improving efficiency over time, consistent with the research and qualitative analysis presented in the present paper. The overall pattern is of market inefficiency over short time horizons, and efficiency over longer time horizons. From the literature review, pp.3-4: Tabak and Cajueiro (2007) show that the Brent and WTI crude oil markets are becoming more efficient in time. Alvarez-Ramirez et al. (2008) show that the market is efficient in long-term, but reject efficiency in the short-term due to auto-correlation. Alvarez-Ramirez et al. (2010) further inspect the crude oil markets and find spot prices to be inefficient. The research on evolution of efficiency in time is further extended by Wang and Liu (2010) where the authors study short-, medium- and long-term efficiency and show that the WTI crude oil becomes more efficient in time for all three analyzed scales. Wang et al. (2011) argue that WTI crude oil spot and futures are not efficient for short time scales below one month. Crude oil markets (Brent and WTI) are also analyzed by Charles and Darné (2009) show that the Brent market is weak-form efficient but the WTI market is not while providing some discussion about effects of deregulation on the markets. Lee and Lee (2009) study coal, oil, gas and electricity to uncover that none of the studied markets is efficient in the strict stationarity sense. Lean et al. (2010) study WTI crude oil spot and futures prices finding no arbitrage opportunities between spot and futures prices while the findings are robust for various sub-periods and critical events. Narayan et al. (2010) study long-term relationship between spot and futures prices of gold and oil. They find that investors use the gold market to hedge against inflation and for our purposes also more importantly that crude oil market predicts the gold market and vice versa implying inefficiency. Wang and Yang (2010) study high-frequency futures data of crude oil, heating oil, gasoline and natural gas using various nonlinear models. For heating oil and natural gas, the authors find market inefficiencies which are profound mainly during bull market conditions. Gebre-Mariam (2011) focuses on the US natural gas market (spot and futures) finding no arbitrage opportunities for daily prices but in general, the author claims that the markets can be seen as efficient only for contracts with approximately a month to maturity. Martina et al. (2011) utilize entropy approaches to WTI crude oil spot prices and find various cycles in its prices. Entropy is also applied by Ortiz-Cruz et al. (2012) who again study daily WTI prices finding the market to be efficient with two episodes of inefficiency connected to the early 1990s and late 2000s US recessions. The authors stress that deregulation of the market has helped improving its

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efficiency. Zunino et al. (2011) apply information theory methods (specifically the permutation entropy and permutation statistical complexity) to the commodity markets allowing them for efficiency ranking finding silver, copper and cotton to be the most efficient commodities. Wang et al. (2011) study the gold market and show that the market becomes more efficient in time especially after 2001. Kim et al. (2011) use the random matrix theory and network analysis to show that stock and commodity markets are well decoupled except for oil and gold showing signs of inefficiency. 55 Fattouh and Van Der Linde (2011) 56 As the IEA’s official history notes: ‘High hopes for a constructive producer-consumer dialogue were seen in the early years of the Agency, leading up to the Conference on International Economic Co-operation (North-South Conference or CIEC) held in Paris in 1976-1977…it [subsequently] became clear in this period that little could be expected from the proposed dialogue…’ (Scott, 1995b, p.325). The Agency’s objective in co-operating with non-Member countries appears in Paragraphs 3-4 of the Preamble to the IEP Agreement where the Members state that they are ‘DESIRING to promote co-operative relations with oil producing countries and with other oil consuming countries, including those of the developing world, through a purposeful dialogue, as well as through other forms of co-operation, to further the opportunities for a better understanding between consumer and producer countries, MINDFUL of the interests of other oil consuming countries, including those of the developing world…’ (Scott, 1995b, p.327). 57 The US withdrew from Vietnam in 1975, a war that was part of a broader conflict in the Indochina peninsula, and a chapter in the Cold War between the US and USSR. In 2015, tensions in East Asia included disputed maritime claims in the South China Sea 58 Claude Duval, Honore Le Leuch, Andre Pertuzio, and Jaqueline Lang Weaver (2009), ‘International Petroleum Agreements-1: Politics, oil prices steer evolution of deal forms,’ Oil & Gas Journal, 7th September http://www.ogj.com/articles/print/volume-107/issue-33/general-interest/international-petroleum.html 59 Exxon Corporation, the largest of the world’s ‘super major’ oil companies, with daily production of just under 4 billion boe, has a market capitalisation of about US$380 billion (as of 21 June 2015), currently the third-highest behind Apple and Microsoft. Exxon (before 1975 under its former name Standard Oil of New Jersey) has been a component of the Dow Jones Industrial Average US stock market index since 1 October 1928. 60 ‘Swing producer’ is not to be confused with ‘marginal producer’, which has become a common mistake with some authors. 61 Prof Richard S Lindzen, MIT, "Taking Greenhouse Warming Seriously," Energy & Environment, Vol 18, No7+8, 2007 62 Yergin (1991) p.720. 63 Sources: Muggeridge et al (2014), Schlumberger, Enhanced Oil Recovery, accessed 18 August 2016 www.slb.com/services/technical_challenges/enhanced_oil_recovery.aspx 64 Based on data from MIT, Observatory of Economic Complexity, http://atlas.media.mit.edu/en/ 65 Quotas exclude natural gas liquids, but the difference is too large to be explained solely by that. 66 ‘Acceptance’ by IEA member countries of OPEC’s decision can be interpreted as either willing acceptance or unwilling acceptance. ‘Willing acceptance’ would imply that the IEA member countries did not consider that OPEC’s announced production cuts met the IEA definition of a ‘disruption to oil supply’ or did not consider that the production cuts would cause ‘economic damage,’ or did not believe that the production cuts would really be implemented as announced. These conclusions are based on (i) the fact that the announced production cuts were large, (ii) the observation that they were of long duration, and (iii) the statement that ‘the primary purpose of an IEA collective action is to mitigate the economic damage associated with a disruption of oil supply ’ (IEA, 2014, Box1.2, p.20). Alternatively, if IEA member countries did consider that the OPEC production cuts met the IEA definition of a disruption of oil supply and did risk economic damage, then the decision not to launch a collective action implies the collective view of the IEA member countries was that it would have been counter-productive to launch an IEA collective action in response, or that an IEA collective action would have simply been powerless to protect against economic damage caused by the OPEC production cuts at that time. 67 Bagehot (1873), p.55 68 Bagehot (1873), p.51 69 Bagehot (1873), p.52-53 70 Other perspectives for looking at oil prices include the marginal cost of production, the ‘fiscal breakeven’ (price required to balance the government’s budget) in key oil producing countries, particularly Saudi Arabia and other OPEC members, and the market power of OPEC itself and its ability to influence prices. 71 Kilian (2014, p.141ff) describes the state of the art in the field, including three problems with the traditional modelling approach, and three proposals in the literature for dealing with them, all three of which ‘… involve major modifications of the baseline DSGE [dynamic stochastic general equilibrium] model of an oil-importing economy to generate quantitatively important effects of exogenous oil price shocks on domestic real GDP.’ 72 While this observation is true for the world as a whole, developing countries and emerging markets tend to go through a phase of development involving increasing oil intensity of GDP growth. That is, oil demand can grow faster than GDP. In cases where motorised transport had previously been under-contributing to the economy due to lack of infrastructure, its growth is an important driver of overall economic growth and increased productivity. China is a good example of this process. In 1978, China had no highways and 51,700km of railway operational length. By

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1988, China still had only 100km of highways and 56,200km of railways. By 2012, China had 95,600km of highways and 98,000km of railways. Rail freight had grown to 3 trillion tonne-kilometres by 2012, but road freight had grown to 18 trillion t-km. In addition to the development of a modern, high speed highway system on a continental scale, China is also part-way through constructing the world’s largest high speed passenger rail network, and airport infrastructure to serve a large country with 1.4 billion people. Growth in passenger transport by road, rail and air shows similar trends to freight transport: enormous growth in rail passenger kilometres, accompanied by a declining share of rail transport, from 46 per cent in 1990 to 34 per cent by 2008. By 2008, the rail system was already moving more than 1.5 billion passengers more than 800 billion passenger kilometres, with an average trip length of more than 500km. 73 Presidential debate between Gerald Ford and Jimmy Carter, September 23, 1976 74 Carlos Pascual, is nonresident Fellow at the Center on Global Energy Policy at Columbia University, was the founder of the Energy Resources Bureau in the State Department and served as the State Department’s Special Envoy for Energy and Coordinator for International Energy Affairs from May 2011 through August 2014. He was Ambassador to Mexico (2009–2011) and Ukraine (2000–2003), as well as Special Assistant to the President for Russia, Ukraine, and Eurasia (1998–2000). He is currently Senior Vice President for International Energy at IHS. 75 Early US LNG exports via the Panama Canal are going to markets on the Pacific coast of South America, not to Asia as originally envisaged when Asian LNG prices were much higher. 76 Last year China lifted part of the veil over its gold reserves, breaking a six-year silence to reveal holdings of 1,658 tonnes as of June 2015 against the previously reported figure of 1,054 tonnes. As of August 2016 it had 1,823 tonnes. Beijing moved to a market valuation of gold, which, according to latest figures, is worth $70.5bn, although this makes up only 2.3 per cent of total Chinese international reserves. China’s total official gold holdings are judged to be sizeably larger. Metal from local mine production is believed to be held in a domestic account separate from the international gold holdings. The world’s biggest official gold holder is the US, with 8,134 tonnes – more than four times that of China and more than five times Russia’s 1,499 tonnes – followed by Germany with 3,378 tonnes, the IMF with 2,814 tonnes, Italy with 2,452 tonnes and France with 2,436 tonnes. (Marsh and Robinson, 2016) 77 For example there is a an ‘inter government Russian-Chinese commission for energy cooperation,’ as described in a Rosneft press release: https://rosneft.com/press/news/item/182363/ involving China’s three largest oil companies: CNPC, CNOOC and Sinopec. Project co-operation to date includes 20 and 25 year long term contracts for oil supply to China and joint ventures for hydrocarbon production. The eastern approach of partnerships between exporting and importing National Oil Companies, led by China contrasts with the western model under which the US State Department provides diplomatic support for the overseas commercial activities of leading investor-owned International Oil Companies headquartered in the US, the UK Foreign and Commonwealth Office plays a similar role with leading UK oil companies, and likewise the French government and other European governments with their oil international companies. 78 See also research by the Centre for International Finance and Regulation, as cited by Lowe (2014) at: http://www.cifr.edu.au/site/Research/Targeted_Research_RMB_Internationalisation.aspx 79 The 2014 data for the value of crude oil (and in brackets total petroleum and hydrocarbon gases) imported by China, as a proportion of the total value of all imports from each country are as follows—Iran: 76 (77) per cent of $25.3 billion, Nigeria: 57 (81) per cent of $2.5 billion; Russia: 56 (65) per cent of $39 billion; Kazakhstan: 49 (53) per cent of $9.9 billion; Turkmenistan: no crude oil, but natural gas is 99 per cent of $8.7 billion. To put these numbers in perspective, in 2014 China imported $1540 billion of goods, of which crude oil was 13 per cent ($207 billion) and other hydrocarbons were 3.5 per cent ($55 billion). Data from MIT, Observatory of Economic Complexity, http://atlas.media.mit.edu/en/ 80 https://en.wikipedia.org/wiki/Chronology_of_world_oil_market_events 81 OPEC, ‘About Us’ www.opec.org/opec_web/en/17.htm, accessed 18 August, 2016. 82 OPEC, ‘Brief History’ www.opec.org/opec_web/en/about_us/24.htm, accessed 18 August, 2016. 83 IEA (2015), Joint Ministerial Declaration on the occasion of the 2015 IEA Ministerial meeting expressing the Activation of Association, November 18, Paris. www.iea.org/media/news/2015/press/IEA_Association.pdf 84 www.wto.org/english/res_e/publications_e/wtr10_forum_e/wtr10_7may10_e.htm#fntext1