from Energy Realpolitik and Energy Security and Climate Change Program

U.S. Natural Gas: Once Full of Promise, Now in Retreat

U.S. President Donald Trump appears before workers at Cameron LNG (Liquid Natural Gas) Export Facility in Hackberry, Louisiana, U.S., May 14, 2019.
U.S. President Donald Trump appears before workers at Cameron LNG (Liquid Natural Gas) Export Facility in Hackberry, Louisiana, U.S., May 14, 2019. REUTERS/Leah Millis

July 2, 2020

U.S. President Donald Trump appears before workers at Cameron LNG (Liquid Natural Gas) Export Facility in Hackberry, Louisiana, U.S., May 14, 2019.
U.S. President Donald Trump appears before workers at Cameron LNG (Liquid Natural Gas) Export Facility in Hackberry, Louisiana, U.S., May 14, 2019. REUTERS/Leah Millis
Blog Post
Blog posts represent the views of CFR fellows and staff and not those of CFR, which takes no institutional positions.

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.

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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.  

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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.  

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