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Chapter 5 Update: Why History Won’t Repeat Itself for OPEC This Time Around

This is an update to Chapter 5 of the book "Energy and Security: Strategies for a World in Transition."

History often repeats itself in the cyclical industry of oil and gas, and market expectations are that the Organization of Petroleum Exporting Countries (OPEC) will be eventually able to organize either a OPEC price cut to lift prices or a major agreement with non-OPEC producers such as Russia, Norway and Mexico, as it did in 1998, to move oil prices back onto a sustainably upward path. Even recent history might imply this is highly possible. In 1999, 2003, and 2009 low oil prices stimulated increases in demand and created an environment where a reasonable agreement between OPEC and non-OPEC oil producers could boost prices substantially.

But assuming this normal pattern of market clearing will take place again as usual looks to be a good deal riskier this time around. This wishful thinking fails to recognize the transformational role that unconventional oil – U.S. shale, Atlantic Basin deep water and Canadian oil sands are playing on the supply side – let alone the impacts of significantly lower oil intensity as well as global climate agreements on global oil demand on a forward looking basis.

While oil prices might rise on an OPEC headline over the next few years, ultimately, the oil sector is facing dramatic and transformational structural changes. The fourth industrial revolution will almost certainly mean that the costs to produce oil from shale and other kinds of source rock including deep water and oil sands as well as from conventional sources of petroleum will decline substantially through technological innovation and learning. Already this year, U.S. shale break-evens have fallen 30 to 40% while reserve estimates have risen and similar cost deflation is unfolding in deep water and oil sands. It’s worth noting that there was virtually no production from any of these three sources of oil at the turn of the century and now combined oil and natural gas liquids production from them has reached over 15-million barrels a day of the world’s 97-million b/d petroleum sector.

Moreover, even with lower prices, technology breakthroughs also mean the outlook for oil demand growth is becoming more uncertain. Not only has the outlook for global GDP growth started to grow dimmer this year, but the relationship between GDP growth and oil demand is starting to diverge in substantial, structural ways. China, which has been the engine to high prices for all commodities and especially energy commodities, is sputtering. Diesel demand in China peaked in 2011 and is looking increasingly unlikely to start growing again any time soon, if ever. Post-COP 21, the United States, Europe and China have committed to actively limit future oil use, with China in particular promoting advanced technology alternative fuel vehicles.  Most tellingly, oil has started to lose its one remaining monopoly as a transport fuel as competition from natural gas and electricity appears inexorably on the rise.

Research by the Sustainable Transportation Pathways Program at the University of California, Davis, finds that efficiency technologies for advanced vehicles, combined with improvements in logistics planning and freight, changes in urban transportation patterns that cap personal vehicle ownership and congestion, and slower than expected economic growth in key Asian economies could easily bring about a peaking of oil demand in transportation in the next decade or so. The question is whether that peak will be temporary. But even if developing world demographics with a rise in the middle class eventually overwhelm such structural changes, oil demand in the transportation sector might only reach 55 to 60 million b/d by the 2040s, according to the UC Davis research, compared to 52 million b/d in 2015 versus ExxonMobil’s 2015 base forecast for 2040 of about 69 million b/d.

Against the backdrop of uncertainty about the structural future oil demand, the idea that traditional producers can impact markets on their own may wind up as “old-speak.” Markets continue to respond as if this is still a world in which OPEC’s low cost producers and some cooperative additional producers (Mexico, Russia etc.) can impose political will to counter market forces. In this previous old world oil order, the United States didn’t count. As a declining producer, it was a price taker whose inexorable net importer status rendered the U.S. relatively weakened as a player on the oil geopolitical stage, except to the extent it was willing to use emergency strategic stockpiles to alleviate short term crises.    

The new world oil order, however, is one dominated by just three giant producers – Saudi Arabia, Russia and the United States – with combined liquids output about 40% of world markets. All three are playing a material role in the global oil supply and demand balance, and one of them – the United States – cannot constitutionally opt to any agreement that would constructively counter-act market forces. We argue that the United States, by virtue of its endorsement of free trade in oil, has laid a deadly stake in the heart of OPEC’s long run market power.

The three giants of the oil market are about the same size. But size is only one element. Who makes decisions is another. In the Kingdom of Saudi Arabia, there is one decision-maker whose authority turns the valves on and off. In Russia, there are more diffuse commercial interests, but at the end of the day, it is the Putin government that is basically in charge.  The third and biggest of the giants, the United States, has production based on competitive decisions of hundreds of independent producers, who now, unshackled, can sell oil at home or abroad.

The diverse and market-oriented U.S. makes an enormous difference, especially when considering the nature of marginal production in the United States which is likely to prove highly resilient in any price recovery.

U.S. shale resources are not only super-abundant, but they can be exploited at a relatively low cost. This counts a great deal because the costs of entry to the US shale are extremely low and this allows the atomistic, fragmented and competitive U.S. exploration and production sector as well as its financial services sector to both increase supply as prices rally and to be very slow and robust in damping supply at low prices.  For example, consider the typical offshore oil well of yester years. Offshore wells cost about $170 million to complete and take 5 to 7 years to first production and an additional five years to payback costs. A shale well, by contrast, can cost under $5 million, with first production coming on line almost instantly to the drilling completion and paying out within five-months. With such a short time frame from the investment decision to first production for shale, U.S. shale production can surge quickly as soon as prices recover again. This is a dramatic difference to 1998 where oil company first production lagged renewed spending in places like offshore Brazil, Africa and Australia for close to a decade.

Perhaps controversially, the Middle East, once thought of as the home to the world’s most abundant low cost of development oil reserves, might in actuality be a higher cost producer.  While oil prices were plummeting in 2014-16, drilling activity reached its highest ever in three core Middle East countries – Kuwait, Saudi Arabia and the UAE. Data on production costs are fairly non-transparent in these core countries. But from public information Saudi Aramco appears to have spent $15 billion between 2003 and 2009 to add 2.85 million b/d to production.  That is higher than the $5-10 per barrel analysts normally pencil in for the Middle East. The giant Manifa field could have been even more expensive in the Kingdom – $7 billion to add 800,000 - 900,000 b/d, not that much below the scale of the most competitive projects in deep water.

Whatever the gossip might be about the need and potential for the old world players to collude to put a floor under prices, at least the leaders in Saudi Arabia understand that it is not that simple – especially now with Chinese oil demand almost certainly sputtering and Iranian and Iraqi production rising.

If Saudi Arabia agrees to sizable production cuts, it confronts two inexorable immediate problems – a potential loss of market share to Iran, which firmly resists production sacrifices of its own because others have taken their market share during their years under sanctions, and the effective subsidy to U.S. independents by causing prices to rise and whose production can grow by perhaps 1-million b/d in a year or so, if and when prices rise.

But longer term, a revenues oriented strategy by Saudi Arabia may be unwise for other structural reasons.

In past decades, the underlying assumption was that oil was so finite that oil prices would have to rise at least at the general rate of inflation. Oil producing countries and oil consuming countries engaged in zero-sum geopolitics where high oil prices impacted GDP in most oil importing countries but not to the same overwhelming extent as in the oil-producing world where oil revenues were often much more than 50% of both national revenues and GDP. In the West, energy’s share of GDP hovered at less than 10%, so OPEC could press higher prices on gasoline consumers since the geopolitical policy costs of trying to counteract the cartel’s market power was largely higher than worth fussing with compared to the inconvenience of living with elevated fuel prices. That essential asymmetry of the distribution of costs allowed OPEC producers to persistently drive a large wedge between their traditional costs of production and market prices.  

Moreover, since the 1980s, the oil industry has operated from the assumption that “easy” to access oil resources would be depleted and the world would become increasingly dependent on the prolific reserves of the Middle East. The assumption was that the higher and rising marginal costs of unconventional oil production would set the market price. Under this long prevailing world view, which lasted from the 1970s until recently, all OPEC needed to do was ride out any temporary downturns until it got to the 2010s and then it would be permanently in the driver’s seat as the purveyor of increasingly valuable reserves.

Through the 2000s and up until last year, OPEC took a revenues-oriented strategy, believing that this constrained “peak oil” world had arrived. Since oil would rise in value over time, it made sense not to produce to maximum capacity and to delay reserve development, since oil in the ground was worth more than oil produced. Private oil companies responded to this world view by seeking to add as many reserves as possible to balance sheets and warehousing the most costly assets.

Now, the concept of a peaking of oil production is, for the time being, debunked, barring the elimination of major capacity via war or domestic upheavals in oil-producing countries.  On the other hand, as discussed above, a flattening of oil demand growth, if not actual peaking, is taking hold as a major risk to old world views. In a world where demand might not grow substantially, then it would stand to reason that companies and OPEC itself would have to reevaluate the conditions under which it makes the produce or not to produce decision.

In other words, even if oil markets tighten, OPEC and non-OPEC producers will have to think twice about delaying the development and production of reserves, lest they disadvantage themselves over the longer time horizon. If oil becomes perceived as increasingly more valuable if produced today, rather than in the future, proven reserves become depreciating assets. Like coal in a world of growing environmental consensus and regulation, even oil reserves could some day as 2040 approaches, become a stranded asset. For Saudi Arabia and Russia who each have between 50 to 100 years of reserves, the prospect that some producers will be left with unmonetizable resources – potentially stranded assets just like thermal coal – ultimately dictates against sustained cartel behavior which would in effect preserve the short term market for higher cost producers such as Canadian oil sands or Brazilian deep water.

In a quite tangible way as well, the new unconventional oil sources – shale oil, oil sands and deep water – have all grown in the Atlantic Basin, once, like the Pacific Basin, a growing deficit market where new Middle East supply could find growing market share.  Now the Atlantic Basin has become an oil surplus region, a structural change not likely to reverse any time soon. That means that Middle East producers are vying with one another for a limited market. These producers can only hope that hundreds of millions of new middle class people in South and East Asia will provide the demand growth needed for them to have market share. Technological change might damp that home considerably.

Thus, all producers like Saudi Arabia with massive reserves are caught between their immediate need for cash and the economics of what would best monetize the remaining oil under the ground. This new world means the zero-sum situation of old, between producers and consumers, has shifted to a zero-sum battle for market share. Thus, chances are neither a sustainable OPEC production cut nor an impactful OPEC-Non-OPEC agreement is likely to be forged, let alone to have the same impact as such an agreement did in 1998.

            Edward L. Morse is global head of commodities research at Citigroup.  He also headed commodities research at Credit Suisse. He has been chief energy economist at Lehman Brothers, cofounder of PFC Energy, executive adviser at Hess and Phillips Petroleum, president of Petroleum Intelligence Weekly, deputy assistant secretary of state for international energy policy, and lecturer at Princeton University.

            Amy Myers Jaffe is the executive director of energy and sustainability at the University of California, Davis, with a joint appointment in the Graduate School of Management and Institute of Transportation Studies.  She is former director of the Rice University Energy Forum and Wallace Wilson fellow for energy studies at the James A. Baker III Institute for Public Policy.