Geopolitics of Energy

A changing climate and growing competition for resources is raising tensions among Arctic nations.

Prior to the U.S. invasion of Iraq in 2003, international sanctions had severely curtailed Iraq’s oil industry. Oil production sat at 1.4 million barrels a day (b/d). Iraq’s beleaguered refining industry was forced to inject surplus heavy fuel oil into oil reservoirs because there was nowhere else to put it. Iraq’s oil industry was debilitated from years of war and sanctions. It took the country billions of dollars of foreign direct investment and over twelve years to restore production to its pre-revolution 1979 capacity of above 4 million b/d. The breakup of the former Soviet Union tells a similar story. Russian oil production declined slowly from 11.3 million b/d in 1989 to a low of 6 million b/d in 1996. It only reached its pre-collapse level of 11.3 million b/d again in 2018. These lessons from history are important because they demonstrate the severe and long-reaching consequences that can result from mismanagement of oil sectors amidst turmoil created by endogenous or exogenous forces. The COVID-19 pandemic has already shown it could produce unprecedented shocks both from the health crises within petrostates and from external forces such as the sudden loss of demand for oil and the accompanying logistical and operational problems arising from oil pricing volatility.     The news that the Organization of Petroleum Exporting Countries (OPEC) plus other key oil producers like Russia had reached a historic agreement on April 12, 2020, to jointly cut production by 9.7 million b/d and that other output reductions would follow from other countries such as Brazil, Norway, and Canada was hailed as a good first step to stemming the tide of a massive surplus of oil that is accumulating across the world. The intervention was welcomed by the G-20 and in particular, the United States, which put its diplomatic weight into the effort to broker the arrangement, hoping to stave off a sovereign credit crisis in fragile petrostates and ease the pressure of mounting global oil inventory surpluses. But just a week later, the difficulties of the arrangement, which does not officially start until May 1, 2020, are starting to emerge. OPEC’s own internal calculations anticipate 300 million barrels accumulated in global inventory in March, with even more to come in April. Energy Intelligence Group reported that surplus floating crude oil storage, which is surplus too, and does not include crude oil in transit at sea to meet anticipated demand, had already increased to 117 million barrels by the end of February, up from 99 million barrels at the end of 2019.   The Wall Street Journal reported late last week that twenty large oil tankers holding a combined 40 million barrels of Saudi crude oil is heading towards oil ports in Texas and Louisiana and are due to arrive in May. Some of the oil was diverted from China, whose shutdown in February left it unable to absorb Saudi oil. But Saudi Arabia also emptied oil from its oil storage facilities in Egypt, Europe, and elsewhere as it was ramping up its declared price war in early March 2020. Now, Saudi Arabia will have to consider if it should slow steam its tankers, that is, have them sail at a slower than normal rate, or even reverse course, to ease the pressure of the arrival of so much oil amidst a continued collapse in U.S. oil demand in the wake of longer than expected economic slowdowns from COVID-19 related directives to shelter in place.   Saudi Arabia owns a 600,000 b/d refinery in Port Arthur, Texas but overall U.S. refining utilization has fallen below 70 percent of capacity nationwide this month in the wake of collapsing demand for gasoline and jet fuel. It is technically difficult for refineries to operate below 60 percent of capacity without turning off some processing units.   The time lag between when oil demand began to crater in February and the point at which the May OPEC Plus oil deal will kick in has created a rush to find storage where it might be available. Over 19 million barrels of crude oil was added to U.S. inventories last week alone. American pipeline companies are requiring companies seeking space on their lines to provide proof of destination certificates verifying there is a refiner at the other end of the pipeline willing to take the oil. U.S. crude oil exports are still moving into ships at the same rates as earlier this year with expectations that firm buyers are still there at the other end. Already, as storage tanks and distribution systems fill, logistical problems and related oil price volatility is worsening. Today, for example, May futures prices for West Texas Intermediate (WTI) crude oil on the New York mercantile exchange (NYMEX) have fallen precipitously to $1.75 as the contract comes towards its expiration date. If the economic demand rebound in May and June in Asia and beyond does not materialize fast enough and at the large scale needed to absorb the world’s oil, continued oil price volatility could be harsh. Recent Chinese traffic data, for example, shows a strong resumption in driving of personal automobiles on the road during work related commuting hours but a still subdued amount of traffic at other times of the day when cars could have been expected to return to the road for shopping and recreational activities.   If global oil demand does not pick up sufficiently in the coming weeks, then lack of access to physical oil storage facilities is bound to cause some oil production to shut-in. Analysts believe that oil production in Africa, Latin America, and Russia could be the most at risk to storage shortage-related curtailments, with potential damaging results for the long run performance of some older oil fields. The prospects that some oil exporters could be forced to close oil fields sooner than others means that all producers have some incentive to take a wait-and-see approach to their promised cuts. In recent years, the collapse of Venezuela’s industry has made room for better prices for the rest of OPEC. Loss of exports from war-torn Libya has also helped.   Despite all the uncertainty or maybe because of it, Russia and Saudi Arabia released a joint statement last week saying that they will “continue to monitor the oil market and are prepared to take further measures jointly with OPEC Plus and other producers if these are deemed necessary.” At the same time, analysts are struggling to anticipate which will come first, a gradual recovery of oil demand as various countries or regions reopen their economies, or damage to oil fields whose operations can no longer continue normally due to financial bankruptcies, severe economic losses, lack of access to storage, or worse still, a severe outbreak of coronavirus among critical offshore workers in a particular location or platform. The uncertainty is bound to create a volatile mix for oil prices in the next few weeks and complicate any future international diplomacy to bring longer range stability to oil markets.  

This is a guest post by Hunter Kornfeind, intern for Energy and Climate Policy at the Council on Foreign Relations and current student at Temple University. A breakthrough agreement between major oil producers and the G-20 has ended the oil price war that began with a conflict between Saudi Arabia and Russia on how to respond to a sharp collapse in global oil demand following the wide spread of the coronavirus global pandemic. The deliberations, highly influenced by diplomatic intervention from the Donald J. Trump administration, brought to the fore questions about how the United States can contribute to a global oil deal to stabilize markets by curtailing U.S. oil production or exports. There is virtually no oil production under the direct control of the U.S. federal government.  The U.S. Naval Petroleum Reserve, which was established in 1912 to provide the U.S. Navy with an assured source of oil, was disbanded starting in the mid-1990s amid changing markets.  To support the broader global oil stabilization program, the Trump administration has said it will lease the 77 million barrels of storage space left in the U.S. strategic petroleum reserve as a means to reduce the rising surplus of U.S. oil production, in effect taking some U.S. oil production off the market and putting it into storage to supplement market-related cutbacks that have already been announced by private U.S. companies.   This backgrounder of frequently asked questions explains how much oil is produced in the United States, what percentage comes from fracking activities in the U.S. shale, and the outlook for U.S. oil production going forward in light of the latest global oil producer deal, and volatile oil prices. This brief also includes some discussion on how the U.S. Presidential election might influence U.S. oil drilling and production going forward.   How much oil does the U.S. produce?  The United States produced 12.2 million barrels a day (b/d) in 2019, an 11 percent increase from 2018, according to official statistics of the Energy Information Administration (EIA). Texas is by far the largest oil producing state at 5.1 million b/d, followed by North Dakota at 1.4 million b/d. Alaskan production was 466,000 b/d in 2019, down slightly from 2018. Production on federal offshore waters offshore Gulf of Mexico stood at 1.88 million b/d, up from 1.76 million b/d in 2018. Close to 65 percent of U.S. crude oil production in 2019 came from tight oil production, of which roughly 4 million b/d came from just three Permian Basin areas – Spraberry, Wolfcamp, and Bonespring – in Texas and New Mexico.  In January 2020, U.S. tight oil production reached an estimated 9.1 million b/d, including 4.77 million b/d from the Permian region and 1.47 million b/d from North Dakota.  Tight oil represented 72 percent of total U.S. production of 12.74 million b/d in January 2020. EIA is projecting February and March data will show U.S. shale production is flattening. Alaska production was 482,000 b/d in January 2020 and U.S. Gulf of Mexico federal offshore was 1.98 million b/d.  The stunning increase in U.S. oil production over recent years results from new, innovative methods of oil and gas recovery, which combines hydraulic fracturing or fracking and horizontal drilling to produce unconventional reserves found in tight oil formations such as shale. Shales hold millions of tiny pockets of resource that have been described by analogy to bubbles in champagne. Fracking involves pumping a water and chemical gel mixed fluid down a well at high pressure to create cracks in shale source rock. Tiny particles of sand in the mix is used to keep the cracks from closing, allowing the production of oil and gas as long as the well remains pressurized. This contrasts with conventional drilling that focuses on a large continuous reservoir of oil or gas from a trap, that is like an underground lake or pocket that can be produced by designing a production system that taps the field’s natural geologic pressure.   Due to the combined effects from the COVID-19 pandemic and low oil prices, analysts are estimating a drop in U.S. crude oil production later this year for the first time since 2016. The latest EIA report currently projects U.S. production to decline by about 473,000 b/d in 2020 and 729,000 b/d in 2021. However, other estimates paint a grimmer picture: consultancy IHS Markit estimates U.S. crude oil production will fall 2.9 million b/d by the end of 2020, cratering below 10 million b/d. Citi estimates that stripper wells that produce less than five barrels a day represent about 450,000 b/d of U.S. total production and will be highly susceptible to closure if U.S. oil prices remain below $30 a barrel.   Low oil prices have led to cuts in capital expenditures across the U.S. industry. The largest U.S. oil majors ExxonMobil and Chevron have slashed their spending by an average 25 percent for 2020, focusing the largest portion of spending cuts on operations in the Permian Basin.  U.S.-based exploration and production companies EOG Resources, Pioneer Natural Resources, and Concho Resources are also reducing their full-year capital spending by about an average 34 percent, also succumbing to the lower crude oil price environment. According to IHS Markit, North American exploration and production companies, to date, trimmed 2020 capital expenditures by a combined $24.6 billion compared to 2019.   The United States has become a major exporter of oil. How much crude oil does the U.S. export? Will cuts in drilling affect the amount of oil to be exported by United States?   In 2019, the U.S. exported about 3.0 million b/d of crude oil, a 45 percent over the previous year. The top destination for U.S. crude oil was Canada, which imported 459,000 b/d, followed by South Korea (426,000 b/d) and the Netherlands (280,000 b/d). The rise of crude oil production over the past decade allowed the U.S. to become a net exporter of crude oil towards the end of 2019, the first time in history the U.S. was exporting more than it was importing.  The United States maintained high exports of crude oil in January 2020, exporting a total of 3.2 million b/d.   However, expected reductions in U.S. crude oil production as a result of low oil prices and the coronavirus crisis could adversely affect exports. The EIA’s forecasts in its most recent Short-Term Energy Outlook that the U.S. will again become a net importer of crude oil and petroleum products in the third quarter of 2020, remaining a net importer throughout the majority of 2021. But, the longevity of this not only depends on trends in U.S. crude oil production, but also U.S. oil demand trends. Government stay at home orders have lowered many Americans’ rates of daily driving, leading to a collapse of demand for gasoline. EIA is reporting U.S. gasoline demand plummeted over 30 percent to a twenty-six year low. Jet fuel use has declined by over 50 percent from usual levels.   Refiners across the United States are reducing refinery runs as refined products begin to buildup in storage tanks around the United States. Shutdowns of refineries in other international locations has allowed U.S. exports of some refined products such as diesel fuel to continue. Depending on configurations of processing units, it can be difficult for refineries to operate at below 60 percent of capacity without shutting down at least partially. To minimize the excess of jet fuel production, U.S. refiners are trying to reduce the percentage of jet fuel that gets produced during the refining process as well as trying to blend some jet fuel back into other product streams, repurposing some tankage to hold more jet fuel or hiring ships to store jet fuel. At some point, it might be necessary to waive the Jones Act which requires the use of U.S. flag ships for journeys in U.S. waters.   Is it possible for an oil price war or low oil prices to “destroy” the U.S. shale industry?  The U.S. Federal Reserve Bank of Dallas reported its most recent Energy Survey that exploration and production firms need an average West Texas Intermediate (WTI) price of $30 a barrel to cover operating expenses for existing wells and $49 a barrel to profitably drill a new well. Whiting Petroleum filed for bankruptcy protection on April 1, becoming the first notable exploration and production company to crumble under lower crude oil prices. Permian producer Callon Petroleum and Chesapeake Energy recently hired restructuring advisors and Moody’s downgraded Occidental Petroleum’s credit rating to junk. The industry already faced numerous headwinds, plagued by leveraged balance sheets and lackluster shareholder returns over the past decade. While the current economic crisis may be the final “nail in the coffin” for some individual firms, the shale resource itself will remain intact for more efficient operators to produce down the road.   When oil prices fell in 2015, several shale exploration and production companies stayed afloat by working out a new debt repayment schedule with bankers. Well productivity gains through technology improvements, hedging, and an eventual recovery in prices by 2017 helped keep many shale players afloat and supported new injections of capital. This time around, some of the largest banks are preparing to take over operations of the oil and gas assets and manage them directly instead of dumping the assets through a bankruptcy process at pennies on the dollar. The hope is that the banks could create vehicles to manage the assets until more favorable conditions would emerge at a later date either through rising oil prices or via a federally-assisted, credit workaround.    For the largest public traded U.S. exploration and production companies, only a small number have large non-revolving debt payments coming due this year. Production declines in the U.S. shale patch are more likely to come from pipeline and storage limitations, rather than outright bankruptcies, in the coming months. Spending cuts and capital constraints could, however, severely limit shale growth into 2021 and beyond if oil prices remain below $30 a barrel. However, chances are if oil prices recover at some point, shale development could accelerate again and growth could be restored, even if the actual companies who controlled the resource changed through industry consolidation or asset sales. The level of future investment will be highly sensitive to perceptions of future market developments.   Among the options considered by the White House during the price war was whether production should be shut down for a time on federal lands in the Gulf of Mexico in light of the COVID-19 pandemic.  However, such an option was not viable because it could potentially have resulted in some permanent loss of producibility of curtailed offshore production. By contrast, shale operators have more flexibility since well completion can be throttled back without fewer, if any, large scale, negative ramifications for future production from the resource. The Texas Railroad Commission, which last regulated state oil production levels in the 1960s and early 1970s, held a hearing this week on whether the state should institute mandated pro-rata reductions in production to prevent the waste of oil resources. Wide differences of opinion were presented at the hearing, reducing the chances of such a policy change, which faces legal, administrative, and political barriers to implementation.    Current Trump administration policy affirms that U.S. oil and gas investment and production is based on market forces and that a market-oriented approach in the United States is likely to produce reductions in oil production in 2020. President Trump’s intervention in the diplomatic process surrounding the G-20 oil stabilization effort was intended to preserve stability of international credit markets, to protect against geopolitical destabilization, in fragile oil producing regions like West Africa and Latin America, and to stave off major logistical problems that could stem from mounting global oil and refined product inventories. The coordinated approach within the G-20 on oil is seen as a continuing process that will require monitoring and refinement over time.   What percentage of U.S. oil demand is met by foreign imports? How much foreign oil does the U.S. import and where does it come from?   U.S. imports of foreign crude oil have been steadily dropping since January 2017 and stood at 6.4 million b/d as of January 2020, or about 30 percent of total U.S. oil demand. Imports from Saudi Arabia have taken a major hit, falling from 1.3 million b/d in January 2017 to 355,000 b/d in November 2019. They recovered slightly in December 2019 to 401,000 b/d. At the same time, crude oil imports from Canada have increased from 3.5 million b/d in January 2017 to 3.9 million b/d in January 2020. Crude oil imports from Mexico to the United States have declined from 730,000 b/d in January 2017 to 614,000 b/d in December 2019 but recovered to 854,000 b/ d in January 2020. U.S. refiners also import other petroleum blending stock materials other than crude oil to supplement the refining process to get the right quality standard of refined products to meet demand. These imports including unfinished oils like residuum, which are imported from a variety of countries including Russia.   Several democratic presidential candidates had proposed a ban on hydraulic fracturing on federal lands during the primaries. Democratic Party presumptive presidential nominee former Vice President Joe Biden has said he supports an end to new permitting for oil and gas drilling on federal lands. How much oil is produced by fracking on federal land? What would be the outcome of a fracking ban on federal land?  The Democratic Party’s presumptive 2020 presidential nominee,  former Vice President Joe Biden promised in a June 2019 climate change plan “… to stop issuing permits for new oil and gas drilling on federal lands and waters.” However, Biden stopped short of supporting a full ban on fracking in the United States, telling a September 2019 town hall that he did not believe a nationwide ban on fracking could get passed in the U.S. Congress. Democratic legislators Senator Bernie Sanders and Representative Alexandria Ocasio-Cortez have each sponsored legislation titled the “Ban Fracking Act” earlier this year and the position is popular with progressive voters. Opponents of fracking highlight problems that some communities have suffered as a result of nearby fracking activities, including contamination of groundwater, air pollution and negative health consequences, and increase in the number of earthquakes in drilling areas. Climate concerns about methane leakage from well sites, pipelines, and processing facilities, as well as from burning fossil fuels in general also play a big role in calls for a fracking ban. The Trump administration is against a ban and has promoted drilling on federal lands, emphasized fracking’s important role in promoting U.S. energy security and enhancing American’s international power and influence.     The Office of Natural Resources Revenue (ONRR), an agency within the Department of Interior (DOI), reported crude oil production from federal lands reached about 2.9 million b/d in 2019 (including Native America and Mixed Exploratory lands). About 64 percent of total federal production in 2019 came from offshore locations, with only about 36 percent derived from onshore fields including those where fracking techniques are prevalent.   Since 2010, crude oil production on federal land has grown at a slower rate relative to production on state and private lands. Production from non-federal land made up about three-quarters of total U.S production in 2019, up about 12 percent since 2010.  According to the ONRR and EIA, New Mexico federal crude oil production reached about 444,500 b/d in 2019, up from just 8,300 b/d in 2010. Almost all of New Mexico’s crude oil production from federal lands originated from two Permian Basin counties – Lea County and Eddy County. Crude oil production in Wyoming on federal lands hit 125,900 b/d last year, up about 37,400 b/d above 2010 levels with more than half coming from Converse County and Campbell County, part of the mineral rich Powder River Basin. Roughly 131,000 b/d of North Dakota’s crude oil production is from federal lands.   While legal experts have questioned whether a federal ban on fracking will pass the courts, analysts also disagree on how much production would be shuttered as a result of a ban on fracking on federal lands. Wood Mackenzie Consultants forecast total U.S. crude oil production could fall by about 750,000 b/d in 2021, if a ban was put into place. This estimate assumes no new wells would be brought into production but that existing wells would continue to produce.   One key factor in determining how much of an impact a fracking ban could have would be how much drilling activity would be shifted to private lands. For example, Consultancy Rystad Energy suggests a fracking ban would likely have no immediate impact on U.S. total crude oil production as capital would shift to private lands as the companies now drilling on federal leases redirect their efforts to other locations to replace lost volumes. Other analysts say that this view is too optimistic and might ultimately depend on market conditions. Current constraints in the availability of capital for shale companies, combined with operational constraints in acquiring new land, permits, lease obligations, and equipment, may potentially provide headwinds for a barrel for barrel shift away from production on federal lands by any particular firm.   What would the national security implications be of a ban on fracking on federal lands?   Prior to the shale revolution, the United States was a major oil importer with imports representing about 60 percent of U.S. oil use or about 12.6 million b/d at its peak in 2005. Since then, dependence on imported oil from the Middle East and elsewhere has declined precipitously. A fracking ban on federal lands alone would not likely return the United States into a major oil importer because the volumes curtailed would be significantly smaller than current U.S. exports of crude oil. Ultimately, the level of future U.S. oil production and exports will likely be a function of oil prices and changes to U.S. oil use. Sustained low oil prices would hinder future investment levels in fracking. However, future trends in U.S. oil use will also influence how much oil would be available for export versus internal use.  

In recent days, the Donald J. Trump administration appears to have been sending mixed messages about oil. Typically, low oil prices can be a stimulus to the U.S. economy, but that is in situations where American consumers can benefit from reducing the burden of the costs of their gasoline use. In what is increasingly moving towards a national lock down to stem the severity of COVID-19, falling gasoline prices pack little punch to the many Americans, who are sitting in their homes out of work and to the rest of working Americans whose pocketbook is focused not on car travel, but on necessary home goods: food, medicine, cleaning supplies, and home maintenance. To keep the logistics of vital goods moving, an army of brave Americans – truck drivers, postal workers, warehouse workers, cargo pilots, and others, are serving our nation. The U.S. oil industry needs to make sure that these valiant workers have the fuel they need. In the case of goods movement, that is diesel fuel for trucks and natural gas for local delivery vehicles.  Right now, there are roughly 140 million barrels of diesel fuel accumulating in storage tanks inside the United States. That is sufficient to support the vial goods industries of the United States for a few months. But storage for other petroleum products such as jet fuel and crude oil is filling rapidly and can become a larger logistics problem, even inside the United States, if it is not managed eventually. Total U.S. on-land inventories of jet fuel are at about 40 million barrels, with only about 10 million barrels left in tankage. As a result, companies are starting to investigate storing jet fuel on ships until demand picks up again. Globally, jet fuel tanks are also closing in on physical limitations, but air travel and refiner flexibility in some locations will be higher than in others. This burgeoning problem of oil storage is yet another reason why the Trump administration is correctly focused on diplomacy to end the oil price war. Time is of the essence since running out of oil storage globally is in no one’s national interest.  The Trump administration has tried to focus G-20 members like Saudi Arabia and Russia on the problem for sovereign credits markets if low oil prices persist. Now, policy makers have to concern themselves with a second order problem. Lack of access to oil storage is going to force shut-in a portion of oil operations around the globe, both refineries and wellhead crude oil production, in some cases potentially with dire consequences. Saudi Arabia has cleverly positioned itself to maximize its access to oil storage, as opposed to Russia which is more disadvantaged in the flexibility of storage in its oil operations. China still has 200 million barrels plus of strategic storage it can offer to desperate oil exporters. The United States has opted to reserve the remaining 77 million barrels of space in its strategic petroleum reserve for U.S. domestic oil producers.  Late last week, Citi analysts calculated an immediate 10 million b/d reduction in global oil production is needed to prevent global oil inventories from reaching maximum capacity. Over the weekend, Saudi Arabia and Russia let it be known that they are making progress towards a deal that would accomplish this. Early proposals included a 2 million b/d cut from both Moscow and Riyadh with another 4 million b/d from other producers. A group including the Organization of Petroleum Exporting Countries (OPEC) was seeking a 2 million b/d reduction from the United States. The Trump administration is pushing for at least a 10 million b/d reduction from the OPEC plus group, which includes Russia, and has suggested that Saudi Arabia contribute more than 2 million b/d to reduction efforts. The United States could need time to work out how it would participate in any Plaza Accord style oil stability program that would come under the auspices of the G-20. Canada has already stated it is open to participation. The Trump administration has already committed to taking U.S. oil off the market by leasing storage in the strategic petroleum reserve and possibly elsewhere. Legal, political, and other technical hurdles to a federal intervention in ongoing private oil company decision making means any additional cutbacks would take time to organize. There is virtually no federally-owned oil production in the United States since the U.S. Naval Petroleum Reserve was sold in the mid-1990s.  If OPEC does not act, lack of storage will force shut-in of crude oil production in any case, since oil demand will be unlikely to recover substantially in the coming weeks. The distribution of remaining storage for crude oil is not equally distributed around the world. According to Cornerstone Macro, most of the available large-scale storage capacity for crude oil is located in just five places: the United States, China, Europe, Japan, and South Korea. The United States and Canada still have a combined, 380 million barrels of tanks available for oil storage.  Some oil producers have already announced production shut-in based on low oil prices, including Brazil (200,000 b/d), Chad, and Canadian oil sands producer Suncor, which has already shuttered a portion of its oil sand mining operations at Fort Hills. Russia’s lower natural gas sales to a struggling European economy almost certainly means a drop in its high condensate production, which was the focus of concern at the December OPEC meeting. Limitation of storage along some of Russia’s export routes are also likely to curtail oil production soon if it cannot gain access to storage from other places. Certain Texas oil pipeline operators are already warning smaller U.S. fracking firms that they may have to turn away their oil by the end of May for companies that do not have existing long-range contracts.  All of the above developments mean that, soon, the determinant of whose production gets curtailed could become a function of access to storage, not oil prices or the cost of production, if a market stability deal fails to materialize. That raises some tricky questions because not all oil fields are geologically alike, and some are easier to close and restore later than others. The nature of how naturally-derived or manufactured pressure drives the oil out of the ground is key to whether turning off an oil field means permanent damage that could result in a loss of productive reserves or not. Saudi Arabia has decades of experience in mothballing and restoring oil field capacity, though occasionally with some difficulties. U.S. shale is uniquely resilient as the pressure for production comes from the artificial means of hydraulic fracturing which can be turned off and on easily. It is impossible to destroy U.S. shale reserves since there is no natural pressure that has to carefully be maintained.  Any time the capital, equipment, and workers are there to produce it, it can be restored quickly in a matter of days or months.  The ongoing crisis in Venezuela has already resulted in some of its smaller oil fields being damaged in ways that the remaining reserves are likely lost forever. This type of permanent damage and loss of reserves could also happen in other places. Several of Iran’s largest oil fields require natural gas injection to produce oil and would be at risk if it cannot maintain a certain minimum production level across the country. Even some deep-water offshore oil platforms could be tricky to restart if they had to be fully shuttered for a long period of time. The technical difficulties of halting offshore production means suggestions that the Trump administration use its authority to close offshore oil production on federal lands could essentially be proposing the U.S. government destroy some percentage of that resource for all time. Finding a legal way to mandate limited, prorated cutbacks from multiple producers, while extremely difficult, could be the best manner for the United States to participate in a G-20 oil stability effort with an eye to sustaining U.S. companies’ ability to restore production capacity at a later date.  The looming shortage of remaining storage means the stakes are high for a major agreement among the world’s largest oil producers to throttle back in order to prevent global storage from filling to excess. It also means that oil production reductions are inevitable, if only because some producers will be thwarted by lack of places to store their oil.  Some U.S. politicians are calling on the United States to impose tariffs on imported oil. Implementation of this suggestion would be ineffective since the shortage of storage means any foreign oil producer who has concerns that shutting-in production would damage their reservoirs, will sell their oil at a loss just to get rid of it. That means they would still dump oil into the U.S. market to get access to buyers and/or buyer’s storage even with tariffs that lowered the profitability of doing so. Some oil is already trading around the world at negative value, that is, at prices where it costs more to produce the oil and ship it, leaving no percentage of funds received for the oil netting back to its seller.  There is disagreement on how long it would take the global oil industry to work off a historic buildup of inventories, were the surplus to reach the 900 million to one billion barrels analysts are calculating in the worst-case scenario. In 2015, when oil prices were cratering, surplus inventories ended the year at 593 million barrels and took two years of concerted producer cutbacks, led by Saudi Arabia, to run down. But that was when the global economy was humming at a 3.5 percent increase per year in Gross Domestic Product (GDP).  Presumably, this time around, it could take longer.  Finally, just as some crude oil exporters will have an easier time adjusting to storage problems than others, localized constraints on jet fuel storage could produce varying degrees of operational flexibility for refiners. That could be a serious problem if the pandemic’s negative influence on air travel is long lasting, given the configuration of the refining industry where it is difficult to produce needed diesel fuel for goods movement and industrial use without also amassing a certain amount of unwanted jet fuel that could not be disposed of. That could be the refining sector’s next big headache, once it recovers from the shock of abrupt loss of demand for its products overall.   

The first priority in addressing the coronavirus is preserving global health. Lessons from the past show that the herculean task requires timely and credible action by governments, coordinating leadership from the World Health Organization, and constructive cooperation among nations. But as containment of the respiratory illness continues to face uncertainties, the fallout of the coronavirus is spreading beyond national and global health systems into the economic sphere. The coronavirus has also taken center stage as a black swan in global oil and gas markets, and first signs are that its influence could be dramatic. Depending how long the health crisis lasts, it is worth considering whether there could be larger ramifications than just a few weeks of market volatility. Many analysts are referencing the Severe Acute Respiratory Syndrome (SARS) epidemic of 2003 in thinking about how long and how extensive the outbreak could be on international travel. Studying similar past events can often provide clues for how a new black swan event can accelerate or decelerate existing trends. One unexpected outcome of the SARS epidemic was that it accelerated the surge in car buying in China in 2003 as urban populations began to shun public transit. Car culture was definitely on the upswing in China at the time. But car sales in China rose by over 30 percent in 2003 compared to a year earlier, as anxiety about being in crowded places elevated. With over 46 million people in China under a temporary quarantine order due to the coronavirus, it is worth considering what unexpected consequences could result this time around. For example, telecommuting could become more accepted and widely practiced post-coronavirus, not because people remain afraid to go to work, but because working or holding meetings remotely could be found to offer productivity gains to businesses, especially where employees are in different locations or time zones. Several Wall Street banks have lowered their oil price expectations for the first half of 2020 based on the coronavirus. Barclays is suggesting the effects could be transitory, with a loss in oil demand from China in the range of 600,000 to 800,000 b/d in the first quarter of 2020, resulting in about a $2 a barrel lower price expectation over the year. Citi’s projections are more dramatic, suggesting current freight and passenger traffic could be down substantially for several weeks, totaling a loss of about 1 million b/d of oil demand off China’s norm of 13.1 million b/d for oil use. Citi estimates freight is running 40 percent lower than usual, with consumer use even more substantially affected. As a result, Citi is lowering their oil price forecast for the first quarter of 2020 from $69 a barrel for benchmark Brent crude to $54 a barrel, warning that a dip to $40 could be possible, especially when combined with current warm winter temperatures. The fall in the volume of global tourism is also hitting jet fuel demand. Chinese tourists made over 150 million overseas trips in 2018, double the rate of the next largest nation of travelers, and were expected to account for a quarter of all tourism by 2030. Beyond flagging oil use, China is currently turning away cargoes of liquefied natural gas (LNG). China’s temporary exit from the LNG market has worsened oversupply in the LNG market already hit hard by ample new production and weaker than usual winter demand. Asian LNG prices hit an all-time record low last week. These projections raise the question of how transitory the weakness in China’s energy importing will be in the coming weeks and whether there will be any long run ramifications for energy use that are not yet anticipated. The U.S.-China trade deal had targeted $50 billion in energy purchases by China of U.S. oil, natural gas, and coal. That figure already looked like a stretch and could be even harder to reach now. Even before the coronavirus outbreak, falling global spot prices for LNG had prompted Chinese state firm Sinopec to delay signing a $16 billion multi-year supply arrangement with American firm Cheniere to purchase U.S. LNG. Trade volumes in global goods, in general, had already taken a hit in 2019 as companies looked to reorganize supply chains to reduce geopolitical risk. That trend is unlikely to be reversed this year, with ramifications for projections that global freight demand would support greater oil use and offset any losses in oil demand that could come from an upsurge in sales of electric automobiles and other inroads for energy efficient technology adoption. For the time being, supply disruptions from Libya and a possible new round of cuts from the Organization of Petroleum Exporting Countries (OPEC) could bail out U.S. independent producers whose revenues, and to some extent, production rates are highly sensitive to oil price trends. But the boost expected to come to the U.S. energy sector from new trade deals could evaporate quickly if China is unable to get its economy back on its feet quickly as a result of the coronavirus outbreak.

This is a guest post by Zoe Dawson, a recent graduate of The Center for Global Affairs at New York University. She was previously an intern for Energy and Climate Policy at the Council on Foreign Relations. Approximately thirty-nine U.S. states have renewable or alternative portfolio standards (RPS), mandating a certain share of renewable power generation within a particular time frame. A small yet increasing number of states have set targets for 100 percent renewable generation. Eight states, including Washington DC and Puerto Rico, have committed to 100 percent clean generation by 2050 or earlier. The most ambitious target, recently set out by Rhode Island seeks to achieve 100 percent by 2030. In comparison to the European Union’s most recent announcement aiming to reach carbon neutrality by 2050, the overall percentage of US states pushing for 100 percent is still low. As we enter the 2020 election year+, it will be interesting to see whether support for renewable energy targets could play a role in the election campaigns. According to the Pew Research Center, a majority of Americans support a range of energy policy priorities; 71 percent in favor of increasing reliance on renewable energy sources and 69 percent who are in support of reducing dependence on foreign energy sources. Not surprisingly, democrats and democratic leaning independents give priority to protecting the environment as well as increasing reliance on renewable energy sources, while a larger share of Republicans put priority on reducing U.S. dependence on foreign energy sources. The midterm elections in 2016, highlighted greater concern for promoting more ambitious renewable energy targets. This was evident in Nevada, with Governor Steve Sisolak calling to increase Nevada’s 50 percent renewable generation by 2030 target to 100 percent by 2050. In Colorado, Jarded Polis is calling for 100 percent renewable energy by 2040. Even more notable, in Michigan, the state’s RPS became a selling point in the campaign. Gretchen Whitmer defeated the states Republican attorney general, Bill Schuette, renowned for his lawsuits against the Environmental Protection Agency (EPA) and opposition to clean energy and energy efficiency. Reflective of Schuette’s electoral defeat, Michigan’s two largest utilities committed in 2016 to boost the fuel mix to 50 percent renewables by 2030. Subsequently, in Illinois, Connecticut, Minnesota. Wisconsin, and New Mexico, elected officials are calling for the increase and establishment of 100 percent RPS targets. Since the midterm elections of 2016, a wave of state level clean energy policies are moving ahead through the eleven new Democratic governors that were elected, seven of which flipped previously from Republican seats. Wisconsin’s governor-elect, Democrat Tony Evers, defeated Scott Walker through a campaign that included pledging to join seventeen other governors committed to the goals of the Paris climate agreement. As more politicians and elected officials in the U.S. push to attain 100 percent renewable power generation, the next big question is around how this can be achieved? Over the last decade, the price of renewables has fallen dramatically. Wind energy has reduced in cost by some 70 percent since 2009 and solar has reduced by an extraordinary 88 percent. This has improved the economic viability of transforming the power sector, allowing the levelized cost of energy for wind and solar to become competitive with that of coal, natural gas and nuclear. However, the biggest challenge with increasing dependency on renewable energy sources such as wind and solar is their variability. Solar energy is only available during sunny daylight hours while wind supply can be intermittent at times. Currently, the state closest to meeting its renewable goals is Vermont, with in state electricity generation coming almost entirely (99.7 percent) from renewable sources, 60 percent of which comes from hydroelectric power. Vermont relies primarily on electricity imports, with the largest share of electricity consumed coming from hydroelectric generators in Canada. Behind Vermont follows Idaho, Washington, and Maine, similarly these states have cleaner power systems as a result of access to hydroelectric generating capacity. Hydropower differs from variable renewable energy resources such as wind and solar, given that is more consistently available with stable output and production. Excess hydro-capacity can be called upon at times of day or seasonally to supplement renewables, though its turbines, like natural gas peaking plants, have technical limitations and adjustments are not instantaneous. Thus, hydro is often used to help balance the grid, as a complimentary source to faster responding energy storage, solar or other power electronic based generator systems. Beyond extra capacity at existing hydroelectric plants, water sources can provide the possibility of pumped hydro storage. Pumped hydro operates through the use electricity-powered turbines, potentially solar for example, to pump water uphill in order to fill a reservoir. Then when electricity is needed, the water is released to flow through downhill turbines to generate electricity. To back up solar power, water is pumped uphill during the day using solar energy and then released when solar energy is no longer available. To the extent that water can be pumped uphill at nighttime --for example, using excess wind power--it can shift the availability of power from overnight generation to serve daytime loads, which adds significant value. Pumped storage hydroelectric power plants are the largest source of electricity storage technology used in the United States. This is both in terms of capacity and number of plants. While there are local variations of hydro inflow as a result of weather patterns, a large share of production capacity is flexible. The usage factor each month for pumped storage usually follows the pattern of electricity demand, a large peak during the summer, smaller peak in winter and the lowest use throughout the rest of the year. Hydropower in the United States currently makes up 7 percent of power generation and 52 percent of current renewable power generation. Roughly half of U.S. hydroelectric generation capacity is concentrated in Washington, California and Oregon. Across the U.S.–Canadian border, 37 major two-way transmission connections between Canada and New England, and Canada and the Pacific Northwest imported and exported 82.4 million mega watt-hours of U.S. and Canadian electricity in 2016. New England and New York accounted for 60 percent of total electricity imported to the U.S. from Canada in 2014, representing 12-16 percent of the regions retail sales of electricity, according to the U.S. Energy Information Administration (EIA). The Pacific Northwest is a net exporter to Canada due to its hydroelectric capacity generating electricity in excess of the region’s needs during high water periods. In 2017, Professor and Director of the Atmosphere/Energy Program at Stanford University, Mark Jacobson released a report which suggested that all U.S. electricity generation could be met with mainly hydropower, wind, solar and storage to achieve 100 percent renewable generation. The study noted that hydropower, in addition to other storage systems like batteries, can be used to balance the variability of other renewable energy sources such as solar, which is not available in the nighttime, and wind that is sporadically intermittent. Battery storage is more cost effective and valuable at providing small amounts of stored energy over a short time at high power levels, while pumped hydro storage is more cost effective at storing and releasing larger amounts of stored energy over longer periods of time. A subsequent study questioned whether stationary energy storage solutions like batteries and the addition of turbines to existing and new hydroelectric dams or storing excess energy in water, ice and rocks could be sufficient to deliver a 100 percent renewables U.S. energy system.  The second study noted that multi-week battery storage systems have yet to be developed and suggested that the ability to develop swing hydroelectric electricity supply could be difficult since addition of turbines could require major reconstruction at existing facilities and the addition of additional supporting infrastructure. In some cases, competing uses for water and environmental constraints might prevent such expansion in hydroelectric capacity, according to the second study authors.   Another challenge to hydroelectric capacity is the possibility that dam removal is sometimes needed for ecological reasons. Given the geographical concentration of U.S. and Canadian hydropower, a decarbonized grid in many locations in the United States will have to rely heavily on wind and solar generation paired with energy storage including batteries. While the declining costs and technology maturation of lithium ion batteries is contributing to energy storage becoming a viable option throughout the United States, unresolved challenges persist for balancing solar power on a seasonal basis in some northern states where hours of sunshine are reduced in wintertime. Other grid organizational models are under study to solve this problem including conversion of renewable energy to hydrogen fuel that can be stored for later use and small-scale distributed energy models that allow smaller batteries to be deployed widely to individual users with diverse usage needs to enhance flexibility to the system. Australia has utilized such a system to stabilize electricity shortages in the Western part of the country. In the case of hydrogen conversion from renewable energy, the technology is still nascent, and some applications remain commercially too expensive to be competitive in today’s markets. Hydrogen fuel also requires special infrastructure given its chemical properties. The Nord Pool, which is a market based power exchange made up of nine Northern European countries is a good example of how increasing interconnectivity can serve as a way to integrate greater amounts of variable renewable energy on the power grid. Most notably, Denmark, which has nearly twice as much wind capacity per capita than any other nation (making up 43 percent of electricity generation) has been extremely successful in facilitating such a high penetration of weather dependent generation through enhancing grid flexibility and interconnectivity. Growing interconnectivity has allowed Denmark to increase its wind energy build. When Denmark is overproducing, it can sell excess power to neighboring countries including Norway, and when the wind is not blowing it can purchase power from its neighbors. The trading of wind and hydropower between Denmark and Norway, above all else, presents a good business case. On average, Norway usually has about a 10 percent hydro surplus every year. When Denmark is experiencing strong winds and/or Danish power demand is low, the price of Danish wind drops, providing profitable arbitrage opportunities for Norway. The planning for scale and encouragement of healthy competition has been critical to the growth of renewables in Europe. As individual states in the United States seek to advance their renewable energy targets, lessons should be drawn from cross-border coordination taking place in Europe and the leveraging of planned transmission infrastructure to provide resource flexibility and take advantage of economies of scale. In comparison, existing interconnectivity between United States and Canadian power markets has seen similar benefits; includes contributing to economic growth through delivering low cost power to formerly underserved regions in the Pacific Northwest. In New England, electricity imports from Quebec and New Brunswick have lowered wholesale power costs and deliver annual economic benefits in the range of $103 million to $471 million. As the U.S. presidential election approaches, election outcomes could be critical to the future pace of deployment of renewable energy in the United States. GOP efforts on carbon emissions have mainly been focusing on carbon sequestration rather than incentives for clean energy. Carbon Sequestration is favored by the fossil fuel industry but yet to be widely commercially deployable at scale. In addition, most Republican plans focus on free market solutions to the climate crisis as opposed to strictly regulating carbon emitters. Recent details on Republican climate plans places emphasis on planting trees, a natural method to sequester carbon. By contrast, the leading democratic Presidential candidates including Bernie Sanders, Joe Biden, Elizabeth Warren, and Amy Klobuchar have all pledged to achieve 100 percent renewable electricity by 2050 or earlier. Democratic contender Michael Bloomberg, a long-time climate activist, released his plan for 100 percent clean energy. Bloomberg’s plan includes extending and expanding solar and wind tax credits and creating new tax incentives for private companies to improve clean energy technology, including battery storage and green hydrogen. No matter the result of the 2020 election, federal policy may not be the leading indicator in the United States where climate and energy policy has been propelled by states and cities. Given the popularity of renewable energy among U.S. constituencies and the falling cost of deployment, renewable energy expansion is likely to remain a major feature of the U.S. energy system in the coming years, catalyzed by state and local policies.  

My grandmother had a saying: “Think before you speak.” The saying, said to me and my brothers as children, was intended to help us avoid mindlessly blurting out something we would later regret. I cannot help thinking of my grandmother’s useful adage in watching the news regarding the ongoing conflict between Iran and the United States. For days, I have been trying to craft a blog on the topic of the current state of conflict across the Middle East. My efforts started before the Christmas holiday when I was trying to update an opinion article I published in the Houston Chronicle in early December about how widening political unrest across the Middle East and beyond could lower the operational resilience of oil producers within the Organization of Petroleum Exporting Countries (OPEC) to respond to unexpected events that could hit global oil markets in 2020. But events on the ground have been fast moving and while this basic point about oil is obviously relevant, it seems now any geopolitical analysis has to start with a better understanding of the geopolitical conditions emerging in the aftermath of the U.S. attack that killed Iranian Commander Qasem Soleimani. Every nation has core strategic interests that do not vary with the personalities leading them or the nature of the ideological bent of a particular ruling elite. We often forget that in U.S. foreign policy and it leads us to mistakes. Iran has a core national interest in making sure there is not a brutal ISIS-led state on its border. That goal doesn’t conflict with U.S. interests. While the escalating events of recent days shows that the United States needs to reflect on the costs that Iran can impose on American interests in an escalating conflict, Iran’s leaders also need to reflect on how their own activities in Iraq and Syria contributed to the outgrowth of ISIS. It is very unclear if destabilization of other neighboring governments is a core national interest of the Iranian population. Proxy militias on the ground can, in fact, have diverging interests from their sponsors. My point is that if strategists don’t ask the right questions, leaders won’t get the right answers. Iran, like any other nation, has many core interests and one of those core interests is to make sure that the government, state military, and militias of Iraq are not a direct threat to Iran’s citizens. It is reasonable for average Iranians, even those who do not support the foreign policy of their government, to have this concern. It is a basic concern that would not go away, for example, even if there was a shift in the Iranian government that ushered in a more benign foreign policy. “Regime change” will not alter this Iranian concern vis a vis Iraq. Any successful U.S. policy must recognize that all nations have core strategic interests that go beyond ideology and often stem from geography. The Islamic Revolutionary Guard Corps (IRGC) news outlets have been running commentaries blaming Iranian President Hassan Rouhani for pushing the country from “a state of peace to a state of war.” The tone of the commentaries, especially in light of subsequent events, could suggest that the IRGC faction believed an escalation in conflict was on its way. But IRGC’s tactical aims and motives shouldn’t cloud analysis of Iran’s geography and how it shapes legitimate core interests of the country. Any negotiations to conflict resolution must consider this. The next step to analysis is to consider the momentum of history. Looking at the conflict between the U.S. and Iran, it is tempting to give in to the sentiment that history is destiny. Americans watched in horror as Iranian protesters and militia leaders stormed the U.S. embassy in Baghdad at the end of December in an event that appeared intended to rekindle historical memories of the frightening capture of U.S. diplomats in 1979. But yet another tragedy is that the subsequent U.S. attack on Soleimani is almost certainly reigniting renewed anger that links to the historical overthrow of Iranian nationalist Prime Minister Mohammad Mosaddegh, who famously led resistance to foreign interference in Iran’s oil industry and political affairs back in 1950s. Conflict resolution efforts must address these historical pathologies head on or risk failure. Iraqi anti-government, nationalist protestors have called for an end to rampant government corruption and a major revamp of the current system of political patronage that enabled Iran’s interference in Iraq’s every day affairs. Iran benefits from overland trade with Iraq that more recently included complex energy arrangements that help Tehran obviate some of the economic pain of the tightening vise of U.S. sanctions. Protests briefly halted production at the smaller Nasiriyah oil field in late December and anti-government demonstrators had also blocked roads to major southern oil fields such as the Majnoon field and even the giant Rumaila field, preventing oil workers from reaching certain sites for a brief period of time. There has been an ongoing risk that some oil workers could consider joining anti-government demonstrators. Unrest seems almost certain to delay Iraq’s plans to implement its South Iraq Integrated Project, a vast water and infrastructure scheme needed for future expansion of Iraq’s oil production and export capability. Thus, there are multiple ways the current U.S.-Iran-Iraq situation could bring about a fresh disruption in oil supplies. Any escalation in ongoing violence inside Iraq constitutes one clear risk to Iraq’s oil exports. If diplomacy aimed to diffuse the situation falters and U.S.-Iraqi relations further sour, the United States could also decide to impose restrictions on Iraqi oil exports if there is evidence that Iran is a direct beneficiary of Iraqi oil trade. Finally, there are risks to the oil industries of other regional players such as Saudi Arabia, which has already suffered attacks linked to Iran. Proxy battles that involved sabotage, cyber, and bombings of Saudi and Iranian oil installations go back two years. Foreign ministers from Saudi Arabia, Egypt, Jordan, Yemen, Sudan, Somalia, Eritrea, and Djibouti met in Riyadh to discuss cooperation in counter threats to shipping along the Red Sea and Gulf of Aden. The United States and Britain are increasing their military presence to protect shipping in and around the Strait of Hormuz. Any diplomatic effort to diffuse the current U.S.-Iranian situation must carefully consider the path forward for Iraq. There is no question that the United States must take into account its broader regional interests, but any solution will need to consider Iran’s core security concerns rather than focusing heavily on its ideological bent. Iraq’s leaders must also weigh the somber reality of the country’s neighborhood. Withdrawal of U.S. advisors from Iraq won’t solve the country’s multitude of problems since there is a long line of other players in addition to Iran ready to fill any vacuum as events on the ground in Syria and Libya demonstrate. It is high time to end the repeating patterns of death and destruction that have characterized the geopolitics of oil in the Middle East. A younger generation of Iranians, Iraqis, and other youth from across the region deserve better. Hopefully, the brinksmanship of the last few days will give all parties involved the incentive to negotiate for different future in good faith.

I have a rule of thumb on the oil price cycle: When commentators start using the word “never” we are typically at the brink of a cycle shift. For a while now, oil prices have been stuck in a range. That stasis has led to much commentary that prices will never go up again. The evidence that oil prices can never rise again came to traders from a simple concept: The all-time, worst imaginable event that could slay oil supply—a successful military attack on Saudi Arabia’s Abqaiq crude processing facility—came and went with only a brief upward whimper in the price of oil. Savvy oil commentator Nick Butler summed it up succinctly, “The events around Abqaiq not only confirmed the immediate strength of supply, but also highlighted the fact that the circumstances that could lead to a sustained price surge are very unlikely to happen.”  Now, complications surrounding the valuation of initial public offering (IPO) of shares in Saudi Arabia’s state oil firm Saudi Aramco are stimulating even more dire predictions about oil. A commentary in the Telegraph noted the Aramco IPO represents “a sobering moment for OPEC [the Organization of Petroleum Exporting Countries]” and adds that “The risk for OPEC and Russia is that the ‘lower for longer’ price stretches into the middle of the next decade. By then, electric vehicles will have reached purchase cost parity with petrol and diesel engines, and much lower life-time costs.” The article is one of many of late suggesting the oil industry is on borrowed time where oil prices have nowhere to go but down. No one is even mentioning the failed auction of offshore exploration blocks in Brazil per se, but it could be taken as yet another sign that oil companies are not in any way desperate for increasing reserves. Still, today’s statistics are not yet proof of the sunsetting of oil prices. World oil demand is not declining this year, compared to past years. Demand is up by 800,000 b/d in the first nine months of 2019, compared to the same period last year. This is less than expected a year ago, but still significant. The narrative that China’s oil demand is falling due to the trade war is also incorrect. Chinese oil demand was 12.7 million b/d in September, up from 12.4 million b/d in 2018. Indian oil demand has also made gains since last year, but at a more modest growth rate of 130,000 b/d. With world demand averaging only a more modest growth rate of 800,000 b/d, U.S. shale takes more than the entire pie, leaving no room for other producers who might have or want to have new oil fields coming online. The International Energy Agency is still projecting growth in global oil demand for 2020 to reach 1.2 million b/d. The optimistic forecast is despite the fact that economic headwinds have curtailed oil use growth in the Middle East and Latin America so far this year. Perhaps in conjunction with announcements about new oil production from giant oil fields in Norway and Guyana, oil traders have a healthy distrust of rosy suggestions that oil market surpluses will shrink. I tend to think of oil prices as cyclical, even if the cycle has been shortened by the U.S. shale boom and related oil price hedging. That is probably why I am finding it harder than usual to jump on the oil demise bandwagon and keep harping back to geopolitical events. But I also find a disconnect between the reality of electric cars and the current narrative that they have already transformed the market. Operating electric cars have amazingly hit the 7 million mark, up from almost nothing a few years ago, but that is out of a global car stock of 1.3 billion on the road today. China is not on a steady path to electrification, either. China has rhetorically indicated that down the road, it plans to ban internal combustion cars. However, this year, it lowered subsidies for electric cars and that has hurt sales. Even if global oil demand is, in fact, soon to be flattening out, as it has already in Europe, there continues to be a lot of dire geopolitical influences on supply instability out there to give pause.  Proxy wars are still raging in the Middle East. This week saw exchanges between Israel and Iranian proxies in Syria. Israeli security analysts are worried about the escalating situation, with one Israeli nuclear scientist suggesting in a major newspaper that the country shut down its nuclear power plant at Dimona as a precaution. Unrest in Iraq is another trigger point for regional conflict. Anti-government protesters briefly cut off roads to the port of Khor al-Zubair where oil exports are shipped and to the entrance of the large Rumailah oil field. Protesters from across sectarian and economic classes are demanding a change in government to redress Iranian influence, corruption, and the current system of political patronage. A recent New York Times and Intercept report recently exposed Iran’s vast influence in Iraq including special relationships with senior Iraqi officials. Iran is unlikely to submit and change its behavior towards Iraq easily given the extensive economic ties that bring billions of dollars in value to the Iranian economy and its ruling elite. Iraq provides Iran with food and other goods in exchange for Iranian natural gas and electricity trade. Iran relies increasingly on this relationship as its economy and people suffer under the Donald J. Trump Administration’s “maximum pressure” sanctions campaign. Iraqi protesters accused Iranian backed groups of employing snipers to put down the mass protests. Similarly deadly, mass protests are also taking place in Iran in the aftermath of the government’s announcement to reduce state subsidies for fuel. It is equally unclear what Russia’s entry into the Libyan war could mean for that country. Some analysts are suggesting that the Russian backed faction might eventually be tempted to disrupt a tenuous truce over control of oil distribution inside Libya. For now, markets seem inclined to discount unrest and war across the Middle East as a feature influencing the price of oil. I am inclined to keep warning that this could be a mistake. But then, that makes me seem like a whiner who can’t let go of an old way of thinking about Middle East conflicts. So I will satisfy myself by reminding everyone that “never” is a really long time when it comes to the price of oil. To date, never has not come to pass.

It has been four weeks since a major military attack on critical oil facilities in Saudi Arabia shocked the world and very little has happened to suggest such an event couldn’t happen again. That begs the question: Why are oil prices falling? If you are a politician sitting in Washington D.C., it could be tempting to explain the calm as stemming from the changed crude oil supply situation of the United States where rising crude oil production – now exceeding 12 million barrels a day – has allowed the United States to become a major crude oil exporter. Citigroup is projecting that the startup of a new Texas oil pipeline will allow U.S. crude oil exports to expand into 2020, up from the 3 million b/d recorded over the summer. That’s created the impression that rising U.S. oil production can replace any disruption from the Middle East. Unfortunately, the numbers don’t actually suggest that. Before the United States takes an energy independence victory lap, it could be wise to consider that America’s crude oil import balance isn’t all that different than it was ahead of the 1973 oil crisis. Yes, that’s right. You did not misunderstand me. I am saying we relied on the same percentage of crude oil imports in 1972 as we do today. In 1973, the United States was a crude oil importer. In 2019, the United States is a crude oil importer. The United States still has to worry about a major disruption in global oil supply. Here are the numbers: In 1972, the United States consumed an average of 16.4 million barrels a day (b/d) of oil. That same year, U.S. crude oil production was 11.2 million b/d and imports of foreign crude oil, to the tune of 5.2 million b/d represented 32 percent of U.S. consumption. By the fall of 1973, U.S. crude oil imports were about 6.2 million b/d. In July 2019 (the latest month for official U.S. government statistics), U.S. crude oil production was 11.9 million b/d, an impressive rise since 2008 when U.S. crude oil production bottomed out at 5 million b/d. Oil consumption in July 2019 was 21.1 million b/d. The deficit of 9.2 million b/d of crude oil or 43 percent of U.S. consumption is complex. That’s because U.S. shale production includes an additional 4.8 million barrels a day of natural gas liquids, some of which can be used in U.S. oil refineries. Ultimately, the United States imported about 7 million b/d of crude oil from other countries in July 2019. We exported 2.9 million b/d of U.S. light sweet crude oil from tight oil plays in Texas, Oklahoma, and other states for net crude imports of 4.2 million b/d. The net import number is about 20 percent of U.S. oil consumption, better than the 32 percent in 1973, but not enough to matter. The 7 million barrels a day of physical crude oil imports from abroad, which includes oil from Mexico and Canada, is 33 percent, roughly the same level as in 1973. The United States is, however, also a large exporter of refined products. Presumably, in an extreme war situation, the United States could limit those exports to prevent physical shortages in the United States. Saudi Arabian oil production represents about 10 percent of global oil supply. If it were substantially knocked out by a second or third military attack, it would be hard for U.S. oil producers to replace that amount of oil in a short period of time. Saudi Arabia was exporting 7.4 million b/d of crude oil prior to September 14 when a combination of cruise missiles and attack drones damaged major crude oil processing plants at Abqaiq and important facilities at the large 1.5 million b/d Khurais oil field. Expedited repairs and redundant equipment and facilities have allowed Saudi Arabia to restore export levels quickly, but a second attack would be harder to bounce back from. Spare oil production capacity is constrained and inventories are being drawn down. Moreover, other regional oil facilities in Southern Iraq, in the United Arab Emirates and in Kuwait could be vulnerable to similar attacks. By comparison, U.S. oil production grew close to 2 million b/d in 2018 and that was an amazing technical accomplishment, but it is less likely that U.S. producers could increase output by three, four, or five million b/d in short order to replace lost Saudi or Iraqi barrels. It would likely take the United States several years to achieve this larger level of increase. While U.S. tight oil production from shale could be expected to increase in three to six months following a major rise in oil prices, bottlenecks could hinder a fast response. Hiring additional work crews, purchasing drilling equipment, and other logistical obstacles could slow down the U.S. industry response initially. The time lag could leave markets more vulnerable to any major disruption of oil from the Middle East that lasts longer than a month or two. U.S. shale production grew less than 1 percent in early 2019 as operational issues plagued firms such as Concho Resources, which suffered a production setback when the company found it was placing its wells too close together. Stock values of some smaller U.S. independent oil producers have taken a beating this year, and some speculators are positioning themselves in credit swaps markets to benefit from any fall in oil prices that could worsen U.S. shale producers’ performance. Institutional investors and their hedge fund managers have seen volatile returns since 2014 when holdings in shale companies turned suddenly negative from the collapse in oil prices. As a result, easy capital to expand drilling programs in the event of an oil price rise could be harder to come by this time around. Giant U.S. independent oil producer ConocoPhillips just announced it was raising its dividend by 38 percent and buying back 5 percent of its shares in an effort to please investors. All of this should mean that oil prices should be carrying a war premium. Instead, prices are falling. Cornerstone Macro suggests in a recent note that it is possible that oil markets have “deduced from all this that the odds of a negotiated way out of strife and sanctions, and an imminent return of Iran’s supply to market” is built into oil price expectations. The macro analysts say they are “less sanguine” about that outcome. It does seem optimistic under the circumstances of escalating attacks on regional oil facilities since January 2018. Europe, Japan, and most recently Pakistan, have actively tried to defuse the conflict between Iran and Saudi Arabia. But even if a ceasefire does seem to take hold in Yemen, for example, the military leverage Iran has over major installations of its neighbors would not be alleviated unless the region saw some substantial movement towards demilitarization of weapons systems. That seems unlikely given the number of active conflicts and internal protests across the Middle East. Another explanation for falling oil prices are fears that oil demand will sink significantly in 2020 as recession grips major economies. Oil demand in the industrialized economies fell by 400,000 b/d in the first half of 2019, compared to a year earlier, including a 200,000 b/d drop compared to last year for Europe’s big five economies – Germany, France, UK, Italy and Spain. Sentiment is that continuation of the U.S.-China trade war will start to take its toll on Asian oil demand as well, though Asian oil demand is expected to average 28 million b/d this year, up from 27.1 million b/d in 2018. Global oil demand is running about 1 million b/d higher this year than 2018 levels. There could also be a simpler, structural explanation for languishing oil prices. There are fewer speculators willing to bet the price of oil up. Many of the heady oil traders known for making big bets have retired in recent years.  Also hedging by oil companies in which shale firms sell their production forward to lock in oil prices as they were rising this fall has effectively kept a lid on the market. The combination of these two market features has lessened the momentum to speculative bubbles in oil. Long-term investors also worry that oil demand will peak eventually as new oil saving technologies take hold and governments act to limit greenhouse gas emissions, and this has reduced interest in long-short commodity funds. Still, on September 14 when Saudi Arabia’s oil facilities were attacked, U.S. oil prices went up 15 percent in one day. Traders who were betting the price of oil would continue to go down had to adjust their bets and that created a large price increase. The problem with Iran has not, in fact, been resolved and markets could see a similar black swan event. Any global event will affect U.S. markets, regardless of how much oil we have at home. Oil is a global commodity and its pricing is determined by global supply and demand. Since the United States is part of the global market and imports crude oil from abroad, U.S. crude oil prices are influenced by global pricing trends. The easiest way to explain this phenomenon is to consider water in a swimming pool. If someone comes with a giant bucket and takes water out of the shallow end of the pool, the water level goes down not just in the shallow end of the pool but for the entire pool equally. By the same token, if more water is put in the pool by a water hose, the water level goes up throughout the pool and not just on the side where the hose pours in. The oil market is the same. If the oil market loses Saudi or Iranian or Iraqi oil, all oil commodity prices are affected for all users of oil, not just users of the disrupted oil. Washington pundits could be advised to keep that in mind as they consider how the United States will prepare for the volatile situation across the Middle East. 1973 could seem like a long time ago and U.S. production could be rebounding, but it is not the case that the U.S. no longer has to “care.” There are 276 million vehicles on the road in the United States of which 99 percent run on oil. We should change that, but so far, we are not moving quickly in that direction. Just saying…

In the swirl of conflicting reports about who might be responsible for the latest attack against Saudi Arabian oil installations, it is important not to miss what makes this latest attack categorically different from past skirmishes. Saudi Arabia and Iran have been engaged in a deadly proxy war for a number of years, and their respective proxies engaged in oil sabotage as far back as early 2018. More recently, Iranian-backed proxies have hassled international oil tankers, bombed an ExxonMobil operations center in Southern Iraq, targeted a key Saudi pipeline, and attacked a strategically important oil storage hub in the United Arab Emirates. These previous incidents, while signaling the vast vulnerabilities of the Gulf region’s massive energy operations, failed to rise to an emergency because the damages involved were relatively easy to ameliorate. Many considered these early aggressions as an ominous warning sign that more serious attacks could come if tensions continued to escalate. That day has arrived. The perpetrators of this past weekend’s attack on critical infrastructure at Saudi Arabia’s second largest oil field at Khurais and its large and vital crude oil stabilization center at Abqaiq selected high value targets that could potentially maximize the size and length of a partial cessation of Saudi crude oil exports. A U.S. government assessment suggested that the Abqaiq facility that is used to strip impurities such poisonous hydrogen sulfide out of raw crude oil to prepare it for shipping and use suffered from direct hits in at least 17 different places. Damaged stabilization towers and gasoil separation plants (GOSPs) that remove natural gas, sand, and natural gas liquids from raw crude, can be costly and time-consuming to repair or replace.  The targets were selected with an eye to disrupt a large portion of Saudi Arabia’s oil deliveries to market for a long time, not the couple of days more typical of a minor pipeline attack or small volume of a diverted oil tanker.  Shutting down oil fields in a sudden, unplanned manner, which resulted from the extensive damage to the stabilization units, can also create its own unique set of problems. U.S. security analysts have been gaming a missile attack on the Abqaiq stabilization complex for years, apparently not terribly accurately.   The immediate interruption of 5.7 million barrels a day of Saudi crude oil exports due to the attack generated the largest price jump in U.K. Brent crude futures on record. The disruption is currently being offset by sales of oil from Saudi storage facilities. Increases in production from unused Saudi oil fields and from spare capacity from other countries such as the United Arab Emirates will provide offsets in the longer run.  About 5.2 million b/d was lost to markets in the aftermath of Iraq’s invasion of Kuwait in 1990. During the eight year Iraq-Iran war that ended in 1988, the oil export infrastructure of both Iran and Iraq was mostly destroyed. The problem moving forward for Saudi Arabia (and for the United States, should it desire to intervene) is that it may prove tricky to thwart new oil-related attacks by Iran and its proxies. It is very unclear if a U.S.-led coalition preventative attack against missile batteries could even be effective. Iranian proxies and direct Iranian military assets are located on multiple fronts along the Saudi border. Distances are close and oil installations of other countries could also become at risk in any forceful escalation of violence. With so many armed parties across the Middle East, identifying and eliminating major threats to oil facilities will be challenging. Such threats can take many forms including missiles, armed drones, and cyber-attacks. Both the United States and most likely Iran have capability to engage in cyberattacks against each other’s electricity networks.  The real question is why has the deterrence of more conflict, even potentially against targets inside the Iranian homeland, failed to discourage such a large jugular attack on Saudi Arabia’s critical oil nodes? The explanation that it is the best way to force a negotiation rings hollow. The larger move against Saudi Arabia’s oil lifeblood puts the United States in a quandary. On the one hand, the Trump administration has been eager to consider stricter measures, including military strikes, that might deter Iran from new provocations. On the other hand, the United States and its allies surely want to avoid triggering a wider conflict. The attacks on Abqaiq and Khurais seem to give Iran several benefits, including putting the Saudi regime under greater financial pressure, creating a vast political dilemma for President Donald Trump in an election year, and enhancing perceptions of Iran’s hard power in the region.   If one could turn back the clock, doing more to end the bloodshed in Yemen might have provided more maneuvering room before things got to this regrettable juncture. Gestures toward negotiations, including the shuffling of higher volumes of IOU Iranian crude oil exports towards Asia and talk of credit lines, appear stillborn. The region is lurching towards potential economic disaster that will be made so much worse as the climate warms.  Iranian leaders might see geopolitical victory on their horizon but it could turn out to be a hollow one for their 80 million people.

Saudi Arabia’s oil industry is on the move with strategic changes in leadership, investments, and a broadening of its global businesses. The moves, which include larger investments in refining and petrochemicals as well as global natural gas, should help the kingdom weather the large changes coming in global energy markets. Studies show that integration across the petroleum value chain can enhance long range profits for large businesses like Saudi Aramco. Saudi Arabia has also focused efforts on reducing the swings of the oil price cycle through its leadership to broker production cut agreements between the Organization of Petroleum Exporting Countries (OPEC) and other major producers like Russia (OPEC plus). Speaking at the sidelines of a major energy gathering, Saudi Arabia’s new oil minister, Prince Abdul Aziz Bin Salman, whose long service in the highest ranks of the Saudi oil sector spans multiple oil boom and bust cycles, told reporters that the OPEC plus alliance “was staying for the long term.”  Even as Saudi Arabia positions itself for the future, current challenges to Saudi aspirations for a higher oil price remain thorny. Continuation of the U.S.-China trade war has raised fears of a recession in Asia, a major growth market for oil use. The Asian economic flu of 1998 ushered in a period of low oil prices. Prospects that more oil will be coming to markets from Iran is another headwind for oil prices. Deterioration of U.S.-China trade relations creates a disincentive for China to abide by U.S. sanctions against Iranian oil exports. French efforts to keep the Iranian nuclear deal afloat is another similar wildcard on the level of Iran’s oil exports. Iraq’s production is also at record levels and the United Arab Emirates is still moving ahead with its plans to increase its oil production capacity to 4 million b/d by the end of 2020. Limited OPEC spare oil production capacity is one factor that has underpins oil prices. Oil price edged higher earlier this summer amid Iranian attacks on shipping and oil installations in and around the Strait of Hormuz but ultimately concerns about a possible weakening in oil demand were attributed as a key variable acting to keep a lid on oil price levels. Markets are also still adjusting to the role U.S. tight oil plays in potentially shortening the oil price cycle. While the U.S. shale industry aggregated capitalization was battered in 2018 in the U.S. stock market, leading some to predict a slowdown in U.S. crude oil output growth, cost-cutting and automation is expected to turn the tide for many companies. Rystad Energy reported that the grouping of the 40 top dedicated U.S. shale companies achieved positive cash flow in the second quarter of 2019, indicating that dilemma OPEC faces in trying to underpin oil prices. The hedging practices of the shale industry also influences the oil cycle. As prices rise, shale producers have moved to lock in prices in futures markets, which in effect adds selling pressures in futures markets upticks. In a presentation to investors, for example, Occidental Petroleum revealed that it hedging program covered a sizable 300,000 b/d of production via a three way collar hedge structure for 2020 that included a short put at $45 (floor sold price), a long put at $55 (floor purchase price) and a short call (ceiling sold price) at $74.09 in addition to selling similarly priced call options in 2021. Non-OPEC production continued to be on the rise this summer, with sizable gains from Brazil and Norway. U.S. oil production is set to gain close to 1 million barrels a day in 2020. U.S. oil production including natural gas liquids was up almost 2 million barrels a day between June 2018 and June 2019. OPEC’s 2019 agreement was helped along by an extended contamination problem at Russia’s Druzhba crude oil pipeline and caused Russian production to hit a three-year low of 10.8 million barrels a day in July 2019. It remains to be seen what Russia’s position will be as its pact with OPEC comes due for renewal in early 2020. The state of U.S. oil production and the overall health of the global economy will likely be pivotal variables. Saudi Arabia’s Crown Prince Mohammed Bin Salman, the architect of Saudi oil policy, discussions with Russian President Vladimir Putin at the G-20 meetings in Osaka Japan lay the groundwork for the current OPEC plus production agreement. But the Russian leader has also expressed in the past satisfaction with current oil prices of $60 a barrel, a level in line with current prices.

This is a guest post by Brian Myers, a graduate student at the Center for Global Affairs at New York University. While the U.S.-China trade war has cast a pall over the previous rosy outlook for global liquefied natural gas (LNG) markets, the signing of new financing deals for U.S. LNG exports has brought room for renewed optimism that rising U.S. natural gas production can find a home abroad. The trend, if sustained, could alter the geopolitics of gas and help U.S. developers even in the face of declining interest from China. LNG now comprises 60 percent of China’s natural gas imports and the country is seeking a more diversified slate of imports. The U.S. delivered 2.9 billion cubic meters per annum (bcma) of LNG to China in 2017, roughly 15 percent of all U.S. LNG exports. Shipments began robustly in 2018 but then trickled to a stop in the latter part of the year. Only 0.3 bcma of imported U.S. LNG reached China in the first half of 2019. While it seemed that trade disputes could slow U.S. LNG development, recent financing deals show that growing liquidity in LNG markets are in the U.S. favor as the global natural gas market shifts to a more commoditized paradigm. U.S. LNG developer Tellurian and French supermajor Total SA reached an agreement in July of 2019 that quietly added some momentum to a growing commoditization reshaping liquefied natural gas (LNG) finance, with potential geopolitical consequences. Total agreed to take an equity stake in Tellurian’s Driftwood liquefaction project for $500 million, in exchange for offtake from the project’s LNG shipments and purchase of $200 million in Tellurian shares. Tellurian will finance much of the project with commercial debt from Driftwood Holdings LLC. The “equity/cost model” being used for Driftwood and other similar projects reflects a progression towards a more liberalized LNG market away from rigid, government to government sponsored financial arrangements of the past such as trade credits or long term government-backed loans combined with equity stakes. Tellurian must now finalize the remaining details for the $28 billion Driftwood project, which has a tentative purchase agreement from India’s Petronet and a deal with trader Vitol to invest and purchase natural gas. The Driftwood LNG terminal near Lake Charles Louisiana would be the largest privately-funded infrastructure project in the United States. Industry officials believe that the Total-Tellurian deal signals an emerging LNG market structure featuring abundant supply sources that will allow for destination flexibility, shorter-term contracts, larger volumes of spot transactions, and critically, a diminution of government involvement. Commercialization of the LNG industry away from state financial sponsorship has been driven by global competition in the private sector to meet potential global demand growth of 40-65 million tons per annum (MMtpa). As demand for LNG rises, the second wave of U.S. projects currently in development is expected to benefit. However, market liberalization faces resistance from powerful energy market players: Saudi Arabia, Russia, and China. All three countries look poised to use their geopolitical positions to influence outcomes in the LNG space. LNG is natural gas that has been cooled and liquefied, which concentrates its volume so that it can be economically transported on tankers and shipped around the world. Natural gas is also exported by pipeline, but this transport mode typically limits cross border sales to regional trade, given the expense to building long-distance pipelines. In contrast to regional pipeline networks, LNG is a globally traded commodity. The LNG industry began as a way for natural gas that would otherwise have been stranded by limited regional pipeline capacity to reach international markets. Algeria became the world’s first LNG exporting country in the 1960’s and since then, Qatar, Australia, and Russia have become the largest LNG exporters. In nascent years, LNG sellers indexed their prices to regional baskets of crude oil in contracts that often stretched out twenty years or longer. Purchase agreements were highly influenced by the role of governments, since reliability was a major concern and development of liquefaction (export) and regasification (import) terminals was extremely capital intensive, sometimes reaching $20 billion or more and requiring years before they can load or receive a cargo. This reality gave LNG a geopolitical tinge that remains to this day. Now, the U.S. shale revolution is rapidly altering the geopolitics of natural gas. By combining horizontal drilling and hydraulic fracturing, the United States suddenly became home to some of the most prolific natural gas producing basins in the world. As the U.S. shale phenomenon has grown, so has U.S. associated gas production from tight crude oil wells in the giant Permian Basin, among other locations. The United States also has cheap, prolific dry gas fields in the Haynesville and Marcellus shale plays. All this has contributed to an abundance of U.S. domestic natural gas supplies, creating impetus to find export markets. As the U.S. oil and gas industry shifted gears from scarcity to abundance, many LNG import terminal projects were reconstructed as export terminals to alleviate an oversupplied U.S. gas market. Prices at the main U.S. natural gas trading and storage hub, called Henry Hub, emerged as a cheap, liquid, and reliable pricing benchmark for North American gas. Henry Hub now has sufficient volume and liquidity to serve not only as the U.S. domestic pricing benchmark but as a potential benchmark index for U.S. LNG export sales, often giving U.S. exports an advantage over more expensive oil-indexed LNG prices. The gas-on-gas indexed LNG sales, such as those tied to a Henry Hub spot market average, has reduced buyer exposure to price volatility in oil markets and allowed abundant natural gas supplies to decouple from geopolitically-driven inflation in oil prices. Recent flare ups in the Strait of Hormuz and their divergent influence on oil and LNG markets exemplify the benefits of gas-on-gas LNG prices. The first wave of U.S. LNG export terminals differed from their global predecessors such as Qatargas and Atlantic LNG in that they were not underpinned by government to government dealings. U.S.-based and private developer Cheniere began the first wave of projects and created a template for all other private U.S. developers in which there was no direct government finance. Cheniere’s merchant template was mostly a function of the United States’ liberalized, market-oriented approach to energy. Now, large international oil companies (IOC) like ConocoPhillips and ExxonMobil, as well as smaller developers like Tellurian, have followed Cheniere’s market- oriented approach. But as Tellurian’s “equity/cost model” suggests, LNG finance for the next wave of LNG export plants could bring even more market flexibility, reducing the need for long run, final destination offtake contracts. To secure project finance with less debt, smaller developers are selling equity stakes in projects that allow investors preferential access to the terminal’s LNG. The “equity/cost model” is allowing second wave developers to tap interest in the growing LNG market where rising liquidity is eventually expected to substitute for guaranteed multi-decade supply contracts. The new financing model presumably will lessen the risk that geopolitical events or a temporary recession will derail a particular project compared to other facilities. Large IOC players like Total are taking more of a portfolio approach to their LNG businesses, building up a variety of opportunities instead of dedicating output in a point to point manner from one particular gas field or terminal to one or two specific government-backed buyers. American natural gas production is uniquely suited to act as backstop supply in an increasingly liquid spot market—allowing U.S. LNG to usurp market share from more geopolitically risky producers. These trends signal changes in geopolitical headwinds that ultimately favor the United States. However, China’s large role as a buyer in the global LNG market means any loss in economic growth in the country could put a damper on not only marginal demand for U.S. LNG but for LNG supplies from elsewhere such as Australia and Africa. China is set to become the fiercest battleground for LNG sellers, hoping to benefit from Beijing’s rising concerns about air pollution and energy supply diversity. Natural gas demand in China is expected to soar to 450 bcm in 2030, up from 280 bcm in 2018. This opportunity has mobilized investment in every link in the global LNG supply chain. Not to be left out, U.S. sellers are considering new financing mechanisms that obviate the need for China to take an equity stake in export terminals. But the U.S.-China trade war remains a potent geopolitical force despite a liberalizing market. The United States’ role in LNG supply to China has been marginalized—only four LNG vessels have landed in the country since tariffs on the fuel went into effect in September 2018. Some analysts believe short-term effects on U.S. producers will be limited; but the trade war clearly delayed some U.S. developers from finding equity investors in 2018. Chinese buyers have turned to Australia, Mozambique, and Russia for long run natural gas supply. In fact, Russia has become one of the beneficiaries from the U.S.-China trade war. Russia’s extensive natural gas pipeline network has been a critical component of European energy supply and European reliance on Russian gas persists because of the very favorable economics of piped gas to Europe compared to LNG. But Europe has also invested heavily in renewables and LNG receiving terminals, making it easier for Europe to limit growth in the percentage of Russian gas supply in its energy mix. Aware of this potential threat to its market share, Russia has moved to develop LNG infrastructure in the Arctic and Yamal regions (using the equity/cost model) to expand its flexibility and reach to other markets. Still, Moscow’s overall natural gas export strategy shows that it still feels its pipeline networks are central to promote guaranteed offtake and reduce merchant risk. That is why it has been pushing for a natural gas pipeline connection to China. The Power of Siberia pipeline represents a concerted Russian effort to lock in the Chinese market. The two countries signed a 30-year sale and purchase agreement that will supply 38 bcma of China’s 280.30 bcma gas demand (2018). Russia is playing a game most other gas exporters cannot: a sustained emphasis on piped gas because it can physically reach disparate markets and undercut LNG prices while also building out LNG infrastructure to compete effectively in other parts of the liberalizing global market. Russia is also drawn to the geopolitical benefits of pipelines, along with their favorable economics. Creating reliance on its gas through a point-to-point pipeline that Moscow controls, Russia maintains leverage on the energy security of its buyers. Natural gas, and the pipelines that transport it, can be tools of economic statecraft that accrue intangible geopolitical benefits to the supplying country, cementing relations in other spheres. Yet, despite its large position in both the pipeline and LNG market, Russia’s leverage vis-à-vis buyers weakens as more LNG volumes are traded on a liquid spot market. Russia could be forced to accept painfully low prices for piped gas if it seeks to maintain market share in the face of abundant global supplies. As Saudi Arabia thinks about its future as a global energy supplier, it is also thoughtfully considering its role in global natural gas markets. Unlike Russia, which has a large position in both oil and gas markets, Saudi Arabia has in the past chosen to play a dominant role in oil and petrochemical markets. But changing conditions for the future energy transition has prompted the kingdom to think more broadly about its long-range strategy. Saudi Aramco’s recent deal with U.S. developer Sempra Energy for a stake in an LNG export terminal reflects a significant shift for the national oil company (NOC) and is a major commercial and geopolitical development. The state-owned oil giant agreed to purchase 5 MMtpa of LNG and a 25% equity stake in the planned Port Arthur liquefaction facility in Texas. Saudi Aramco’s decisions move markets and by agreeing to the same financial arrangement used in a commercialized U.S. LNG space, it has buttressed the liberalizing trend in LNG markets. If the world’s largest NOC eschewed a direct intergovernmental agreement for LNG investing and instead prefers to participate in the growing open market, it shows how strong the trend towards commoditization is in the future global gas market. Aramco’s acquisition is also geopolitical significant. Many countries in the region are oil and gas producers while Saudi Arabia relies heavily on oil to sustain the kingdom’s economy. As global oil demand slows in the coming two decades and LNG demand surges, diversification of energy assets is critical for Saudi Arabia to remain competitive with both regional rivals and other global energy suppliers that export both oil and gas. The investment also strengthens Saudi Aramco’s commercial ties to the United States. In the face of LNG market liberalization and increased global competition, the U.S. diplomats seem to lack a clear international strategy. The capitalist system in which U.S. LNG developers operate precludes the Trump administration from acting unilaterally to increase the competitiveness of U.S. LNG in the global market. Industry commercialization means that governments could take equity stakes in fewer future projects, and federal subsidies for U.S. LNG are unlikely. Market liberalization is a double-edged sword for U.S. LNG developers—as the market becomes more competitive resulting in cheaper LNG closer to large Asian demand centers, some second wave U.S. sellers could struggle to achieve LNG price netbacks necessary to sustain profitability, potentially putting export volumes at risk. Even though the United States is in large part responsible for increased global competition and market liberalization, how competitive U.S. LNG shipments will be in this new market remains to be seen. The problem is sufficiently thorny that old fashioned ideas of the Texas Railroad Commission restoring production quotas is making the rounds in some natural gas circles. This is unlikely to help given the plethora of other available resources to meet demand worldwide. While the Trump administration has limited options to boost future U.S. LNG volumes directly, an early end to the U.S.-China trade war would certainly mitigate some of the risks to current project development. U.S. LNG export sales would definitely be hit by any slowdown in Asian economies. And, U.S. LNG developers are still hoping there will be a rebound in LNG exports to China once a trade deal could be settled. The president’s team have also courted potential other customers for U.S. LNG but ultimately market forces and geographical price arbitrage between various destinations will determine demand for U.S. natural gas globally. Workers dependent on energy and agricultural trade in the U.S. Gulf of Mexico states, particularly Louisiana, are already facing economic hardship from the trade war. The longer the Trump administration continues to escalate trade tensions with China, the greater the risk for the U.S. LNG industry.

This guest post is co-authored by Joshua Busby, associate professor of public affairs at the Robert S. Strauss Center for International Security and Law at the LBJ School at the University of Texas at Austin, Sarang Shidore, a visiting scholar at the LBJ School at the University of Texas at Austin, and Morgan Bazilian, director of the Payne Institute and a professor of public policy at the Colorado School of Mines. Increasing interconnection of electricity systems both within and between countries has much promise to help support clean energy power systems of the future. If the sun isn’t shining or wind isn’t blowing in one place, an electricity grid with high voltage transmission lines can move electricity to where it is needed. This shared infrastructure and increased trade can possibly serve as a basis for peace between neighbors in conflict, but it may also serve as a tool of coercion if the electricity can be cut off by one party. Cross-border trade in electricity is currently dominated by Europe – 90% of the $5.6bn electricity trade market happens there, but in the future increased trade in electricity, particularly in Asia, is set to grow dramatically. The boldest proposal comes from the Chinese organization GEIDCO which has, with the backing of the State Grid Corporation of China (which reportedly has over 1 million employees), promoted regional and even global grid integration. On the one hand, such grid integration could foster greater interdependence in conflict zones and facilitate more shared interests. But there is another concern, what we call a strategic denial of service. This would be a form of what Farrell and Newman refer to as “weaponized interdependence,” a situation where one country uses a shared relationship asymmetrically to extract political concessions from another party. Emerging economies China is providing ample financial support for electricity and energy initiatives through the Belt and Road Initiative (BRI) and the Asian Infrastructure Investment Bank (AIIB). As much as two thirds of BRI projects, worth some $50 billion, has been invested in the energy sector. Some observers have already raised concerns about what China’s overtures in this space might mean for its neighbors. Phillip Cornell, writing for the Atlantic Council, warned that despite the benefits of grid integration: "Even if local grids are independently operated, deep interconnection means that supply and demand will increasingly be      matched across the super-grid, making them more interdependent. It may be managed by 'international rules and operation code' as Liu [Zhenya, GEIDCO's chairman] insists, but those will be defined by a regional authority where China is bound to have major influence." The scope for cross-border trade in electricity isn’t only Chinese-led. Even as India has been trying to integrate its domestic grid through what it calls green energy corridors, the country is also supplying electricity to some of its neighbors. India already exports some 660MW to Bangladesh, and Indian firms are building power plants which could meet as much as 25% of Bangladesh’s electricity needs. While India is currently supplying power to Nepal, Nepal has the potential capacity to supply hydroelectric power to India. Nepal and Bangladesh are also considering electricity trade through the intermediate Indian network. Hydro plants in the Mekong Delta from Laos already supply electricity to neighboring Thailand, making it its top source of foreign exchange. Other projects include CASA 1000, a proposed power line to link the Kyrgyz Republic and Tajikistan as well as an interconnection linking a hydro power station in Malaysia’s Sarawak to West Kalimantan that should diminish Indonesia’s dependence on imported oil. Can electricity be used coercively? Can a state use electricity as a coercive tool like the way Russia has used natural gas? Is this technically possible? What are the limits? In the case of gas, you have a product that can be physically stored for periods of time, whereas electricity is a much more ephemeral product that, absent viable storage at scale, is lost as waste heat if not transmitted to end users. Though a breakthrough in storage might take away some of the urgency of the threat of service denial, it wouldn’t remove it in the event of a prolonged outage. Technically, the process of denial of electricity service is not all that difficult. Shutting down power service across a transmission system is just a matter of operations control (in the absence of good governance, power markets, contracts, etc. that are all in place to avoid disconnection of service). It can be done virtually instantaneously to disconnect power from any node on the system. Think of “rolling blackouts or brownouts” when different parts of a service area are shut down for various technical or economic reasons. Curtailing electricity to another country is potentially costly for the coercer. Curtailing electricity transmission to a neighbor does mean foregoing payments for the electricity (provided the neighbor was paying their bills). But, it could be one that states will use to generate benefits such as higher rates of payment for electricity or, more broadly, to extract concessions on other matters of political importance. For some energy sources like hydro power, the water has other potential uses. This could enhance the attractiveness of using service denial as a coercive tool since the owner of the hydro could presumably monetize its water in another way. A state might try to insulate its vulnerability to service denial through widespread conservation or building in extra reserve capacity, but in some settings and seasons, demand reduction might not be so easy to achieve. A country might be able to find alternative sources of electricity either from other neighbors or by powering up more expensive domestic sources of generation, though those arrangements could take time or prove much more costly than the existing cross-border arrangement. The flipside of denial of service would be demand curtailment, which a state might pursue if it was attempting to punish a neighboring electricity supplier by reducing its revenues.  Has this been done? During the Cold War, the Soviet Union was able to maintain dominance over Eastern and Central Europe by tying their energy supplies to the Soviet energy grid, reducing their scope for independent action. Though privatization in the early years of the break-up of the Soviet Union provided these countries with more independence, Gazprom made a conscious effort to acquire assets back under Russian control, sometimes under commercial conditions that could be construed as coercive, particularly in the natural gas space. Baltic states and Poland remained tethered to the Russian electricity grid. It was not until 2018 that Estonia, Latvia, Lithuania, and Poland completed an agreement to decouple from Russia and transition to the EU grid by 2025 at the cost of $1.2 billion. Fears of potential Russian service denials helped them overcome remaining obstacles. There have also been some examples in the post-Cold War era of denial of service and other forms of coercion related to integrated grids and interdependence. In July 2018, Iran cut off a portion of power to Iraq over unpaid fees in the midst of a summer a heat wave. While this may have merely been to ensure Iraq paid its balance, other states have employed similar tactics for more expansive purposes. In February 2019, the Trump Administration threatened secondary sanctions on Iraq to discourage its purchase of imported Iranian electricity and natural gas. Here, the service denial is not by the generator but by an influential third-party who has its own political axe to grind with the Iranians. In June 2019, the United States provided Iraq with a temporary four-month sanctions waiver to allow Iraq to get through the summer by importing products from Iran, lest the country experience a wave of unrest as it did in 2018 when Iran cut the power.  In May 2019, the United States and the Maduro government in Venezuela clashed over the rightful ruler of the country. Before and after the departure of Venezuela’s diplomats, left-wing U.S. protesters occupied the Venezuela embassy in Washington, D.C. to prevent supporters of the opposition Juan Guaidó from seizing the embassy. In the midst of the dispute, the power to the embassy was cut off by the electricity provider PEPCO, raising questions about political involvement by the Trump administration. If we think of the embassy as sovereign territory of Venezuela, this would qualify as a case of cross-border service denial and speaks to the potential vulnerability of other such enclaves such as military bases that may depend upon electricity grids of host countries. In July 2016, Turkey temporarily cut power to the major US airbase in Incirlik in the wake of the coup attempt against President Erdoğan, underscoring these concerns about base vulnerability. Cyber-security experts have also raised the prospect of denial of service by hackers who might be able to penetrate an electricity grid and take it off line. Given that communications, transport, and health care infrastructure all rely on electricity, the cascading effects of such an outage could have far-reaching consequences. If carried out by shadowy non-state actors, it might also be harder to attribute responsibility to a state actor. In December 2015, in the first known instance, Russian hackers were able to briefly take off line three Ukrainian distribution companies. Which states might deploy this strategy? We are more likely to see strategic denial of service where markets and contracts give private actors limited legal recourse in the event of supply disruptions. Moreover, strategic denial of service may be more common where there are large power asymmetries between neighbors, particularly but not limited to non-democracies. The more powerful state can use the size of its military apparatus or economy as additional leverage to extract concessions. In our view, we are less likely to see a poorer, smaller country like Nepal or Lesotho try to deny electricity to a more powerful neighbor, given the risks of reprisals. Similarly, in the event of demand curtailment, we might see powerful states use this tactic against neighbors that are highly reliant on electricity export revenue. As Farrell and Newman argue, those that control central nodes are likely to possess asymmetric power at key chokepoints: “Specifically, states with political authority over the central nodes in the international networked structures through which money, goods, and information travel are uniquely positioned to impose costs on others.” In a bilateral sense, a small chokepoint would be the ability for one country to deny service to one downstream power importer, but if a single actor exercises control upstream over the entire transmission network, that would provide them with asymmetric power over a wider group of actors. If no state controls a single node but several states together control electricity exports, that would require the kind of collective action that is less likely to occur in most regions of the world. In the event that the ambitious Desertec project moves forward, a study of the scope for North African countries to use renewable energy denial to Europe concluded that it was unlikely to succeed unless all five exporter countries curtailed service. Authoritarian countries may use this tactic more than democracies. In authoritarian governments, private actors may have less arms-length relationships with the government and thus be susceptible to pressure to cut off service to foreign countries. However, powerful democratic countries may also use this tactic against adversaries and non-democracies. Outside the electricity space, we have even seen the United States try to use its control of SWIFT banking system to coerce other democracies to avoid trade with Iran. In the electricity arena, it is less clear when democracies might use denial of electricity as a tactic. That said, if the U.S. government did in fact have a role behind the scenes in cutting off power to the Venezuelan embassy, this would be an example. As countries seek to balance their electricity needs to have the cheapest, greenest source of power when they need it, they may become both importers and exporters of energy. This may reduce the temptation for a state to unilaterally cut off electricity to its neighbor, lest the whole cooperative relationship fall apart. However, in a world of increasing concerns about sovereignty, we may see fewer of these interconnections to start with, absent confidence building measures and institutions. Can this tactic be prevented? To reduce the risks of coercive actions in cross border electricity trade, regional governance treaties and related multinational institutions should be created to oversee the implementation of agreements for the grid's operation. This could be akin to a neutral regional grid operator that has representation from all countries. ASEAN, for example, is helping develop the regulatory framework as the ASEAN Power Grid is built and knits countries together. OLADE -- the Organización de Energia Latinoamerica – is seeking to play a similar role in Latin America. Ideally, markets, contracts, and legal forms of dispute resolution would also help ensure that politically motivated service denials do not happen, but market mechanisms on their own are unlikely to establish confidence in grid integration across borders. Regional institutions remain an important means of regulating the trade, along the lines of transborder water governance that Lucia De Stefano and collaborators write about in terms of institutions to apportion water, deal with shocks, and carry out dispute resolution. Chinese acquisition of electricity assets in Portugal, Greece, and Italy have led Europeans to raise questions about whether existing forums for transmission operators such as ENTSO-E ought to be elevated to a regulatory body. Other regions are likely to be even less coordinated in terms of regulatory oversight. As Cornell points out, the vision for GEIDCO from the founder is one of decentralized, technical administration like the internet, without central control, but that actually betrays how the internet is subject to national level suppression as we have seen in countries like China with the Great Firewall. Other new Chinese-led institutions like the AIIB are subject to multilateral oversight, suggesting a governance model that might attenuate some of these concerns. In the absence of institutions to guard against politically motivated service denials, countries will remain disconnected or even seek to decouple their systems from neighbors deemed too risky. In much of the electricity space where the potential is largely untapped, it would mean foregoing many of the benefits associated with integrated grids. Poorer, weaker countries needing power might have few options and accept the Faustian bargain that puts them at the mercies of more powerful neighbors. At a moment when our collective emissions of greenhouse gases already have tied us together in mutual vulnerability to climate change, it would be a shame if joint efforts to address the problem got caught up in the return of great power politics.  

Oil is a global commodity where prices adjust to a supply disruption in one place across all locations, no matter country or location where the problem started. To help people understand what that means, I like to use the analogy of a swimming pool. If one takes a giant bucket of water out of the deep end of a swimming pool, it affects the water level for the entire pool, not just the deep end. The larger the bucket, the more swimmers will notice changes in the water level throughout the entire pool. The upshot of this global nature to oil is that freedom of movement of oil through the Strait of Hormuz is a global problem. Countries might think that maintaining “good” relations with Iran might mean their ships won’t get attacked, but it is not truly relevant. If anyone’s ships are attacked, the oil disruption that could ensue will affect all oil importing countries. The International Energy Agency (IEA) was formed out of an understanding of this notion of the global nature of the oil market. Emergency stock releases need to be coordinated because if one country releases strategic stocks and other countries hoard oil instead, the net supply gain to markets can be cancelled out, hence coordinated stock release policy is advantageous. IEA announced this week that it is prepared to act if oil flows are disrupted from the Middle East. Iran may feel it is getting an upper hand by showing it has been wronged and is a nation to be reckoned with. The problem is Tehran is also showing the world what a problem it could become if it actually had nuclear weapons capability. This week, governments from the U.K. to Germany and to Japan will have to decide how much force to apply to protect oil shipments in their vessels and flag ships. But what if Iran were a nuclear power? The calculus would be quite different. The bargaining process for conflicts where parties have access to missiles with nuclear warheads is altered. Nuclear weapons add additional risk on the party that desires to change the status quo. One can expect the cost is higher for third parties who would want to intervene in regional conflicts. A future nuclear-armed Iranian declaration that only the oil Tehran dictates will be allowed to transit the Strait of Hormuz would present an even more complex situation than today’s geopolitical challenge of sanctions and shipping. The military problem of protecting shipping would become more dangerous and potentially require a military campaign to destroy any active Iranian nuclear warheads before engaging conventional Iranian forces that are blocking free transit of the Strait. The history of nuclear deterrence theory suggests Iran would never use a nuclear weapon, even if it had one because of the extreme consequence of enormous loss from a second strike. But the possibility of internal political instability can in itself alter a bargaining process. One might have imagined Iran would not have taken such a decisive act against British vessels for fear of attack by the North American Treaty Organization alliance. NATO did, after all, intervene in Libya in 2011 under a situation perhaps less clear than blockage of an international waterway.  That leads me to question whether Iran may have overplayed its hand. Now that the strategic risk of a nuclear-Iran is so much more transparent, would Europe still feel it can afford to provide nuclear technical assistance to Iran including equipment under the terms of the 2015 Joint Comprehensive Plan of Action (JCPOA)? China must also see the detriment to itself of a nuclear-armed Iran. It’s easy to facilely link the escalation of tensions with Iran on the Trump administration’s “maximum pressure” campaign, which has disturbed an already tense status quo but now thoughtful analysis needs to be made regarding what the current situation has taught about the war-ready nature of factions within the Iranian government. Some lessons are relevant to future diplomatic solution-building regardless of how we got here. The reality is that conflicts involving Iran throughout the Mideast proceeded – and in some cases escalated- even after the JPCOA took hold. The opportunity that signing the nuclear deal would moderate Iran’s foreign policy regarding regional conflicts and assassination plots in Europe was unrealized, even before the Trump administration reversed the U.S. commitment to the JCPOA. As Europe moves forward in trying to fashion a solution, Iran (and Russia) will need to consider the changing nature of the global oil business. Iran has to concern itself with the future geopolitics of stranded oil assets. Removing itself now from oil and gas commodity markets and direct foreign investment opportunities at this pivotal time in oil’s potentially declining future might have long lasting negative consequences for its energy industry. Moreover, any military exchange that raises oil prices sharply could become the impetus that the West and China needs to accelerate the shift to low carbon energy more decisively. Such a result would reverberate in Moscow whose natural gas giant Gazprom is already struggling against a rise in renewable energy in Europe. China, which has never participated in a large global oil supply cutoff as a giant oil importer (it was self-sufficient in energy in 1973, 1979, and 1990), may also need to educate itself about the consequences of having one fifth of its oil supply have to traverse the Strait of Hormuz. China has more to lose from a poor outcome between the West and Iran than the West does given its lesser dependence on Middle East oil. Tehran may decide that its resistance economy is good enough for regime survival and choose the path of continued confrontation. That would be a tragedy for the entire region and present a serious challenge for the United States. The makeshift response to allow Britain to protect its own shipping calls into question whether the U.S. could abdicate (either on purpose or by accident) its vital superpower naval role which regulates sea lanes and, in effect, facilitates global trade. The consequences of the U.S. withdrawing from such a role is unthinkable for all concerned, even for the Chinese, who may seem to object to U.S. ships in the South China Sea, but, in reality, free ride off of U.S. air and naval power in so many aspects of their economic life. China should be careful what it wishes for. The Trump administration must avoid reconsidering this critical naval role nonchalantly. It is central to the United States’ global authority.  Just the appearance of U.S. hesitation about that role could invite unwanted seafaring military incursions and piracy across the globe. If Iran decides that conflict is better to regime survival than concession, the Trump administration’s lack of a well thought-through, implementable strategy regarding Iran will become an even larger problem. Oil markets will increasingly lose their imperviousness to risk as more speculators bid oil prices up. Regional allies could also become more insecure. All this means that now would be a good time to move away from ideological bents and study up on years of U.S. military gaming exercises regarding the Strait of Hormuz. The U.S. military has years of study and knowledge to fashion and lead an effective international coalition for diplomacy and deterrence in the Strait of Hormuz. It should use it.