Geopolitics of Energy

Western leaders have long criticized OPEC’s power to raise oil prices, and the bloc continues to influence the global market even as U.S. oil production has soared and alternative energies have come to the fore.  

Ethiopia is moving in the right direction, but still has plenty of work to do to overcome multiple crises.

This is a guest post by Gabriela Hasaj, Research Associate to the Military Fellowship Program at the Council on Foreign Relations. Tessa Schreiber, intern for Energy and U.S. Foreign Policy at the Council on Foreign Relations, contributed to this blog post. Mirroring events that rocked the international oil industry earlier this year — catalyzed by the fallout from the COVID-19 pandemic — a now sluggish global economy is hitting the liquefied natural gas (LNG) industry. Like oil before it, prices of spot LNG around the world are collapsing, storage is rising, and LNG exporters are responding to mounting challenges. The situation spells bad news for the nascent U.S. LNG export business and the geopolitical benefits it bestowed on the United States. Dominant natural gas exporters Qatar and Russia are responding to the current LNG supply glut by accelerating their own mega-projects to lock in market share for the next ten years and beyond. Their moves could set back the U.S. LNG export industry for years to come, depending on the state of global economic growth in the coming years. Already, forty U.S. LNG cargoes have been cancelled for August pushing the total cargo cancellations for this summer over one hundred, bringing total U.S. LNG exports to half of capacity. Goldman Sachs estimates that 4 billion cubic feet per day (Bcf/d) of U.S. gas exports will be cancelled this summer.  Just a year ago, the U.S. natural gas industry saw few obstacles to becoming a major LNG exporter due to the U.S. shale revolution and the growing liquidity in LNG markets. A more liberalized LNG market funded through an “equity/cost model” was indicative of a shift away from traditional government to government sponsored financial agreements, with potential global demand growth of 40-65 million tons per annum (MMtpa). Interest in U.S. LNG was driven mainly by commercial considerations, with favorable future price curves for the Henry Hub benchmark, the main price link for U.S. LNG, giving buyers the impression that U.S. LNG was both geopolitically reliable and highly economical. However, today, U.S. LNG producers find themselves in a very different situation, one that may have them wishing for the days when the U.S.-China trade war was their main obstacle.   The International Energy Agency (IEA) recently released its 2020 LNG Outlook, with forecasts for a 4 percent drop in global natural gas demand as a result of global lockdowns to mitigate the spread of COVID-19 and low heating demand due to warm weather. The bleak outlook does not take into account the possibility of a second COVID-19 wave. Additionally, global storage is brimming at almost 2.8 trillion cubic feet (Tcf) of working natural gas as of May, 18 percent more than the five-year (2015-19) average. The economic incentive for buyers in Asia and Europe to import U.S. LNG has disappeared, as the U.S. natural gas Henry Hub benchmark is now hovering around $1.70 per million British Thermal Unit (MMBtu), too high compared to Asian $1.95/MMBtu and European $2/MMBtu spot prices once transportation and other costs are taken into account. Even when the actual U.S. natural gas spot price is lower than global spot prices, additional costs associated with U.S. LNG exports impact their economic viability. U.S. gas exporters charge an additional cost for liquefaction, typically around $2.00 to $3.00 per MMBtu, and tanker transport from the U.S. Gulf coast to Asia currently varies from around 60 cents to Japan and 81 cents to China. The rule of thumb is that the Henry Hub spot price should be about $2.00/MMBtu lower than other global spot prices in order for buyers to breakeven. Asian spot prices rebounded 20 percent from record lows, but they still do not make U.S. exports profitable. U.S. feedgas demand for LNG exports since April fell from just above of 8 billion cubic feet per day (Bcf/d) in the first quarter of this year to 6.4 Bcf/d in May and 3.9 Bcf/d in June. These poor market conditions and cargo cancellations come at a time when three major U.S. LNG terminals, Freeport, Cameron, and Elba Island, just came online in 2019. After running at full speed until April, the six operational U.S. export terminals are now using only 65 percent of their capacity, mainly for take or pay shipments of gas under long range contracts.  The paltry sales of U.S. LNG to China as part of the January 2020 U.S.-China trade deal will do little to prevent rising exports from Qatar and Russia to discourage financing for future U.S. export projects. According to figures from the U.S. Department of Energy, China imported 21.1 Bcf of U.S. LNG during the month of April 2020, after Beijing started granting tax waivers to some importers. But this rare bright spot was short lived as U.S. exports to China have dwindled to two ships in June and one booked for July. For now, China appears to be shifting the sources from which they import their natural gas, cutting certain pipe gas imports, in favor of cheaper LNG spot imports. Chinese interest in spot LNG is rebounding based on demand from independent Chinese buyers such as ENN Energy Holdings Limited and Jovo Energy Co., who have access to terminals. To save money, these independent companies are taking the bare minimums required under their long-range gas contracts, in effect, exercising downward quantity tolerances (DQT) of their offtakes, and thereby replacing a small portion of their contract supplies with cheaper short-run, spot LNG imports from regional suppliers such as Qatar and Australia.  In the longer run, U.S. LNG also faces a formidable challenge from other low-cost producers who are expanding future export capacity. Qatar has said it will not slow its North Field Expansion (NFE), which will increase their LNG production to 110 million tonnes per annum by 2024, from current 77 million tonnes per annum. The small Gulf state, home to the United States’ largest air presence in the region and U.S. Central Command’s (CENTCOM) forward headquarters at Al-Udeid Air Base near Doha, is actively challenging Russia’s stronghold on the European natural gas market. In addition to its long-range planning, Qatar is actively adding supplemental shipments of LNG to European ports to bolster its market share as prices continue to fall. For its part, Russia, is responding by taking concrete actions to ensure it can expand its sales to China by committing to construction of a second $55 billion giant pipeline project to bring its Siberian gas through Mongolia to Jilin and Liaoning, China’s top grain hubs, just miles away from Beijing. According to Gazprom, the Power of Siberia 2 pipeline could supply as much as 50 Bcm/y to China annually. The costly pipeline is not projected to come online until 2030. This is not the first collaboration between Gazprom and Chinese energy interests — Chinese entities have provided tens of billions of dollars in loans for energy projects to capital-poor Russia since the 2008 financial crisis. The second pipeline supplements the existing Power of Siberia pipeline, already in operation since December 2019, which has transported around 300 million cubic meters per month of natural gas to China from the Kovyktinskoye and Chikanskoye gas fields in eastern Russia. The second pipeline is aimed to help Russia diversify its markets away from Europe in the long run, given expectations that natural gas demand could decline over time in Europe due to rising use of renewable energy and strict carbon emissions policies. Russia is still moving forward with the Nordstream-2 pipeline despite currently flagging European demand and competition from the United States and Qatar for market share. Analysts expect Russia will cut prices to ensure its pipeline natural gas can compete for market share in Europe. Russia’s Yamal LNG, operated by Russian firm Novatek, also gives Russia flexibility for water-borne shipments in summertime that can go east or west depending on market conditions. Novatek is also inaugurating ice breaking LNG tankers for its Yamal routes.   Cargo cancellations and LNG project delays will challenge U.S. LNG merchant companies such as Cheniere, Venture Global, Tellurian, and Sempra Energy, to remain competitive through this global supply glut. Although Cheniere has seen the most cargo cancellations, they are also the largest U.S. LNG producer and exporter and use a fixed-fee contract model that essentially ensures the terminal operator a stable cash flow. The fixed-fee model requires that the buyer pay a tolling fee to reserve capacity, regardless of whether or not they take any LNG. These long-range sale and purchase agreements (SPAs) account for 79 percent of Cheniere's first-quarter income, and give the buyer the option not to lift the cargoes as long as they notify the exporter forty-five to sixty days before the delivery date and pay the tolling fee. Tellurian, on the other hand, recently delayed its target to begin construction of its flagship Driftwood LNG export terminal in Louisiana until next year. The delay resulted after critical equity partnership agreement and offtake agreement with India’s Petronet fell through. French oil major Total, previously agreed to increase its investment in the Driftwood project and to buy 2.5m tonnes of LNG a year. But the firm has issued a securities filing giving it the right to back out of the agreement if the Driftwood project is not online and running by 2021. Sempra Energy has also delayed a final decision to at least 2021 on a $9 billion project in Port Arthur, Texas. With such weak market conditions and new capital investments in U.S. production and export capacity on the rocks, the promising outlook of U.S. domination in the LNG market that was projected in early 2019 now looks extremely unlikely.  All eyes are on China but it is unclear that the Chinese market will be the savior some had been hoping. The U.S.-China Phase 1 Trade Agreement, a purported truce in the multi-year trade battle between the U.S. and China, included a Chinese commitment to purchase more than $50 billion in American energy products over the next two years. Analysts say that this arrangement does not look feasible. Earlier in February 2020, Chinese LNG buyers had filed force majeure notices in the attempt to get out of contracts amid the COVID-19 pandemic. Although China’s LNG imports have resumed, even prior to the COVID-19 pandemic, the Asia-Pacific region was already experiencing an oversupply of gas. Now that there has been some loosening of COVID-19 restrictions, natural gas demand in China has remained steady for the most part, with a slight increase. Over the first five months of 2020 China has imported 1.9 percent more natural gas than in 2019.   The fallout from Russia and Qatar’s moves to aggressively defend market share have broad implications for LNG exporters from other regions. High cost Australian LNG export projects were already faltering while the outlook now for other new capacity, such as projects mooted from the United States, Mozambique, and the east Mediterranean, look cloudy. The changed situation could be bad news for major U.S. producers from the Permian Basin such as ExxonMobil and Chevron, who were counting on strong export markets to supplement U.S. domestic gas demand. The EIA forecasted that the U.S. will reach 89.7 Bcf/d in domestic natural gas production this year, compared to U.S. domestic consumption of natural gas of roughly 81.9 Bcf/d on average for 2020. U.S. natural gas demand is projected to drop to 78.66 Bcf/d in 2021 due to rising renewable energy supplies. With natural gas exports waning, and storage filling quick, flaring, the practice of intentionally burning surplus gas, has been on the rise. Even before the demand impacts of the COVID-19 pandemic, flaring was intensifying, particularly in the Permian Basin, totaling at about 293.2 billion cubic feet in 2019 as more associated natural gas was being produced than could be absorbed by pipelines. U.S. Permian producers are under mounting pressure to reduce flaring, raising questions about how to achieve higher oil production and still have an outlet for rising volumes of associated gas.   The detrimental impacts of the pandemic on natural gas demand has called in question the viability of continuing U.S. LNG leadership in global gas markets. The U.S.-China trade war had already set back contracting for long run U.S. LNG projects, giving Qatar and Russia reprieve to grab customers at a critical time when gas sale contracts were up for renewal. There is no question that the United States and its allies benefit from the competition that U.S. LNG can provide to global gas trade. But it is unclear in the new environment how the United States can ensure that high dependence on Russian and Middle East gas doesn’t create geopolitical risks anew when economies recover in the coming years. Managed trade deals like the one negotiated in China have not delivered concrete results. In a policy brief by Rice University’s Baker Institute, experts suggest that a minor change in the interpretation of the requirements of the U.S.- China trade deal — essentially, allowing long-term purchases from new or expanded U.S. export projects to count toward the import commitments under the Phase 1 Agreement — could prove beneficial for both parties. China would benefit from reliable long-term purchase agreements, underpinned by equity in new LNG liquefaction facility, providing China with a committed supply source and flexibility in FOB purchase agreements. The U.S. would secure long-term offtake commitments from China and in turn benefit from the positive impact of investment and job creation through the fulfillment of the $50 billion purchase requirement.   For now as things currently stand, it is possible that U.S. producers missed their chance to dominate global natural gas exports. It would take a concerted effort to lock in renewed foreign equity investment for U.S. LNG export terminals with guaranteed offtake agreements to keep U.S. gas flowing, and such deals will be harder to conclude now not only because the commercial outlook is less attractive and also because foreign investment in critical U.S. facilities reasons may be less geopolitically appealing to all concerned. Only time will tell if this missed opportunity consequentially alters the geopolitics of natural gas in the years to come but for now, the U.S. LNG renaissance is in retreat.  

Prior to the COVID-19 pandemic, India was moving to the forefront of the global energy transition, with plans to reach 175-gigawatt (GW) of renewable energy by 2022. Prime Minister Modi’s decisive electoral win in May 2019 seemed to have secured continuation of India’s ambitious solar energy goals, but now the COVID-19 outbreak of early 2020 is slowing and delaying new solar energy construction on top of other challenges the sector faced. The fate of India’s push to clean energy has global implications, since India is a major economy and lowering its carbon emissions is important to global efforts to address climate change.

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. Russia is coping with a new reality from the lasting effects from the brief crude oil price war with Saudi Arabia this past spring and the ongoing COVID-19 pandemic that has left Russia’s domestic energy industry in its most difficult position since the breakup of the Soviet Union. Delivering an unprecedented production cut – around 2.5 million barrels per day (b/d) in May and June according to the terms of the recent agreement between the Organization of the Petroleum Exporting Countries (OPEC) and other major oil producers – in an accelerated manner left Russian oil companies with the difficult decision to select what wells to keep going and what wells to idle. Depending on how long oil production reductions are needed, cutbacks in specific Russian regions could potentially lead to some permanent shut-ins due to operational challenges across an industry with little storage capacity and natural geological constraints in a large number of maturing fields. Production curtailments could also affect the quality of Russia’s main crude oil Urals export blend, which is a mix of oils coming from different production streams. Variability of quality can alter the desirability of a crude oil in the export market, thereby influencing its value to refiners. These challenges are exacerbated by the fact that Russia’s oil trade faces strong competition from Middle East exporters in its key markets in Asia and Europe amid flagging demand caused by economic slowdowns. A deterioration in domestic consumption also poses headwinds, so much so the Kremlin recently banned certain oil product imports to protect the Russian market from a wave of cheap fuel.  Russia is fully committed to the historic 9.7 million b/d production cut agreed by the OPEC+ producer coalition of which it is a member. The Kremlin reaffirmed that commitment in announcing publicly today that there was “close coordination” between Saudi Arabia and Russia on oil output restrictions. The Kremlin is hoping its constructive role in fostering the final agreement to stabilize global oil markets could create a diplomatic opening to improve relations with the United States, which took an unprecedented public diplomatic role in pressuring the parties for the oil agreement, ultimately fostering cooperation between top Russian and Saudi leaders. Russian Energy Minister Alexander Novak recently met with major Russian oil companies to discuss a possible extension of the current level of production cuts past June. Much will depend on market conditions in Europe, where demand is beginning to recover. A longer period of curtailments could pose operational or geological difficulties for some Russian producers, including Russian flagship oil and gas firm Rosneft PJSC. Russia has been angling to get some U.S. sanctions eased, especially those applied to Rosneft PJSC, which is no longer trading Venezuelan oil. The technical challenges in Russia’s oil sector could give impetus to Moscow to want to gain access to capital markets for its oil sector as well as U.S. technology and industry assistance. It is unclear where diplomatic progress can be made in the complex U.S.-Russia bilateral relationship that ranges from concerns about future nuclear proliferation agreements to the difficulty of reaching a diplomatic solution to the humanitarian crisis in Venezuela as well as Russia’s continued military presence in the Ukraine, among other active hotspots. This week, the United States chided Russia for its alleged role in escalating conflict in Libya, in an indication that tensions remain on a wide range of issues.   Still, other geopolitical conflicts aside, Russia has a point in noting the significance of its contribution to global oil market stability. The 10 percent year-over-year decline in Russia crude oil production, described in April by Russian Energy Minister Novak, would make 2020 the first year of a double-digit decline in crude oil production since the early years of the Boris Yeltsin presidency. Following the collapse of the Soviet Union in 1991, Russian crude oil production reached a low of about 6.0 million b/d in 1996 according to the BP Statistical Review of World Energy, declining from about a record 11.4 million b/d in 1987. The state suffered from sharp declines in oil production from 1991 to 1994 when the Russian oil sector was under reorganization and little to no capital investment was made in new wells. Only after more than two decades of strong oil company investment, equating to hundreds of billions of dollars, has Russia able to restore its crude oil production capacity to return to its Soviet-era highs.  Russia currently has about 200,000 active wells, more than most other crude oil-producing states. Compared to Saudi Arabia’s lower per barrel cost of production, Russia’s hydrodynamic methods – including horizontal drilling, sidetracking, and hydraulic fracturing – are capital and labor intensive, especially with the country’s older wells. Reactivating a well that is throttled back can be challenging. For some wells, the longer a reservoir remains idled, the higher the chance pressure, water content, and clogging could affect future production. Experts say curtailment decisions will ultimately hinge on the characteristics and geological constraints within production regions. Companies have to assess where it makes the most technical and economic sense to make the cuts, either in brownfields – fields that have matured to a production plateau or even progressed to a stage of declining production – or in greenfields – a new oil and gas field development – throughout Russia. Increases in COVID-19 cases at Russian crude oil assets could also lead to production difficulties in select regions due to quarantines.  West Siberia, an oil producing region in central Russia that extends from the northern border of Kazakhstan to the Arctic Ocean, continues to be Russia’s dominant producing region and contributes more than half of Russia’s total crude oil production. Most fields operating in the region are older, conventional reserves. They are facing permafrost melting and rising associated water levels, which reached 86 percent on average in 2018. According to a study from the SKOLKOVO Energy Centre, Russia’s largest active Siberian brownfields reported a 22 percent increase in drilling rate penetration from 2012 to 2016 but recorded a 5 percent decrease in total crude oil production, demonstrating how Russia’s older fields require more intensive methods to keep production growing. Yuganskneftegaz, Rosneft PJSC’s largest unit with operations in West Siberia, cut crude oil production by about 289,000 b/d between May 1 and 11 from February levels, according to Bloomberg News. Lukoil PJSC, the second-biggest Russian operator, decreased output by about 312,000 b/d compared to February with almost half of the production cuts originating from fields in West Siberia.   Before the OPEC+ cuts, Russian companies were actively exploring greenfield development in remote onshore regions like East Siberia and the Russian Far East, attempting to offset declining production elsewhere in Russia. The shift had been successful – greenfields continue to yield higher production growth compared to legacy brownfields. According to analysis from the SKOLKOVO Energy Centre, Russian greenfield crude oil production grew 77 percent from 2012 to 2016, reaching 21 percent (roughly 2.3 million b/d) of total crude oil production.It remains unclear whether the current oil price environment will hamper continued greenfield investment and production in Russia. So far, Russian oil companies have not abandoned their large-scale investments, instead deferring them in hope of a rebound in global oil prices and eventual relief from the OPEC+ production limitations. State-owned giant Rosneft PJSC announced plans to continue the development of new fields but is "postponing short-term less economically viable projects" and “…high risk long-term projects, including joint ventures.” Russia could have difficulties staying the course, however, given the departure of some Western majors, who continue to slash capital expenditures. Royal Dutch Shell recently withdrew from its proposed onshore joint venture with Gazprom Neft in the Arctic, citing a “challenging external environment.” The current low oil price environment may discourage future Western investment in Russia’s upstream, which also continues to face complications from Western sanctions.   In addition to cash flow consequences and possible damage to oil fields or equipment, Russia’s continued oil production cutbacks could create a marketing headache for Russian firms. Russia’s most popular crude oil blend for export, Urals, is a mix of different grades of crude oil from different regions in West Siberia. As production cuts occur, the mix of crude streams going into Russia’s export pipelines can change, shifting the quality of the export blend and thereby its value to refiners.   Already, amid slumping petroleum demand due to COVID-19 pandemic lockdowns, Russia faces lower demand for its crude oil exports. Rystad Energy estimates crude oil demand in Europe declined 38 percent year-over-year in April and expects demand to slump 13 percent year-over-year for 2020. Chinese demand is slowly recovering following the easing of stringent lockdown measures, helping Russian export sales.   Russia sells roughly three-quarters of its total crude oil exports to just two markets Europe and Northeast Asia, much of it by pipeline delivery. In China, Russia has gained market share since the COVID-19 crisis began, replacing curtailed oil from Iran and Venezuela which recently reached all-time lows. China imported about 1.7 million b/d of crude oil from Russia in April, about a 14 percent year-over-year increase. That compares to about 1.2 million b/d in Chinese imports from Saudi Arabia. Shipments along the East Siberia-Pacific Ocean (ESPO) oil pipeline to the Kozmino export hub near the port city of Nakhodka in the Russian Far East point to a 24,000 b/d month-over-month gain to about 757,000 b/d in May to customers including Japan, South Korea, and Singapore, according to Energy Intelligence Group. In addition to linking to the Kozmino export hub, the ESPO pipeline connects directly to China via the Skovorodino-Daqing spur, an about 660 mile long pipeline transporting oil from Russia’s Far East to China’s Northeast province of Shandong, home to half of China’s teapot refineries and nearly 70 percent of teapot refining capacity.   !function(){"use strict";window.addEventListener("message",function(a){if(void 0!==a.data["datawrapper-height"])for(var e in a.data["datawrapper-height"]){var t=document.getElementById("datawrapper-chart-"+e)||document.querySelector("iframe[src*='"+e+"']");t&&(t.style.height=a.data["datawrapper-height"][e]+"px")}})}(); The recent success in oil sales to China contrasts to struggles in Europe and domestically. Seaborne crude oil shipments from the Baltic Sea ports of Primorsk and Ust-Luga are set to see a 620,000 b/d month-over-month decline in May due to reduced refinery runs and lackluster demand across Europe. March crude oil shipments via the Druzhba pipeline, the longest pipeline in the world, fell about 125,000 b/d month-over-month in April and may experience more headwinds in the coming months. Domestic demand for crude oil has also cratered amid the COVID-19 pandemic. Deputy Energy Minister Pavel Sorokin explained in April that domestic gasoline, diesel, and jet fuel consumption has fallen by 40 percent, 30 to 35 percent, and more than 50 percent, respectively, due to the shutdown of the Russian economy in light of the pandemic. Data shows gasoline production for the first six days of May declined to about 572,000 b/d, down about 40 percent from March levels as about a third of Russian products output is consumed domestically.   Although the OPEC+ agreement is finding very successful implementation, Russian and Saudi Arabian exports are still competing for similar customers going forward. Now, the United States could be added to the mix as the Trump administration is calling upon China to honor its bilateral trade pact, which included increased purchases of U.S. crude oil by China’s refiners. The negotiated increase in U.S. energy purchases, however, has been hampered by China’s economic contraction in the first quarter of 2020. Rebounding oil demand may help paper over such differences when the OPEC+ coalition meets again in less than two weeks, but there will be a lot to navigate beyond June as oil producers try to build on momentum created by the historic deal made in April.  

The process of going into lockdown due to the coronavirus pandemic has been revealing, especially in regards to oil. There are many elements to the smooth operation of global oil logistics that are now facing potential problems due to the unprecedented lockdowns. Here are a few of these elements and the complications the lockdown process is exposing.

Iraq faces an uphill battle in meeting its obligations to the historic production cut agreement reached by the Organization of Petroleum Exporting Countries (OPEC) and other major producers such as Russia. The production cuts are due to begin today. Not only is Baghdad mired in deep economic and political crises that show little signs of abating but Iraq’s complex service agreements with international oil companies (IOCs) operating its southern fields means that the Gulf producer would actually have to pay more money to the foreign firms working in its oil sector in excess of existing service fees if it demands the IOCs rein in output to help Iraq meet its targeted quotas. The supplemental fees, which could be millions of dollars, are stipulated in the oil field service contracts that Iraq holds with foreign oil companies that have been assisting with its oil production capacity expansion program over the last several years. The payments structure for Iraq’s service contracts means that output cuts put an added financial strain on the ability of OPEC’s second largest oil producer to comply fully with its pledged one million b/d plus output reductions in the coming months.