Energy Realpolitik

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.