Gas Line, Q3 2020

October 1, 2020

Gas Line is a quarterly publication that looks at major news stories in global gas—ranging from project development to markets and geopolitics. My goal is not to cover every story but to draw connections between stories across time and space in order to shed light on the major themes that will drive global gas markets in the years ahead. My main takeaways from this quarter:

Suppliers Cut Production to Balance Markets

The bottom line: Major suppliers cut production in response to historically weak prices, and those cuts helped prop up prices, more so in Europe and Asia than in the United States. Unlike in oil, this adjustment happened without any coordination among major suppliers and without major breaks to the system (besides the occasional revision to contract terms). But prices fell to unprecedented lows, and stayed there for weeks, before production cuts led to a rebound in gas prices. The United States led in reducing liquified natural gas (LNG) exports, while Russia reduced its pipeline exports to Europe (but not its LNG exports; similarly, pipeline exports in the United States held steady).

The backstory: Henry Hub reached a 25-year low on June 25 and has since recovered. Prices rose by 80 percent in the span of two months before falling again in September. The Title Transfer Facility (TTF) in the Netherlands bottomed on June 1 and has since almost tripled—prices are now near where they were in January 2020. A similar rally is seen in the Japan Korea Marker (JKM), which hovered around $2 per million British thermal units (MMBtu) for months before bouncing up to around $5 in the end of September. The spread between U.S. gas prices and those in Europe and Asia, which briefly turned negative this summer, has been restored.

From peak to trough, LNG exports from the United fell 70 percent (based on daily deliveries of pipeline gas to export terminals). Exports from Russia were down 17 percent in the second quarter, after falling by a similar amount in the first quarter. Norway’s pipeline exports were down 5 percent (through August). Qatar’s LNG exports rose through August, while Australia’s declined on a month-on-month basis relative to their peak in January but are up on a yearly basis since new projects are still coming online and ramping up. This production adjustment helped push up prices but also left a lot of gas in storage: in both the United States and Europe, stocks are far higher than their five-year average. This overhang might cause problems for any sustained recovery in gas prices into 2021.

Companies Announce Big Impairments, but Finance Still Flows

The bottom line: During second quarter results, companies announced billions in impairments from gas projects, feeding a narrative that LNG megaprojects in particular were becoming or risked becoming “stranded assets.” But most of the impairments came not from a shift in the long-term outlook, but from a bearish forecast for oil prices in the medium term, which lowered expectations for gas prices. Those lower prices hit recently completed projects with high costs, chiefly in Australia. And, at the same time, a lot of new capital flowed into the sector to support new projects or to recapitalize existing projects and companies.

The backstory: Several companies announced impairments during their second quarter results, and many of those came from LNG projects in Australia. Shell announced impairment changes of $8.2 billion ($11.2 billion pre-tax) in its Integrated Gas segment, mostly from the Queensland Curtis and Prelude projects. Total referenced “assets located in Australia” for its $829 million charge (in net income) in its Integrated Gas, Renewables and Power segment. BP took a $11.1 billion charge in its upstream segment without offering a detailed breakdown, but several of the announced positions include gas assets that could have been affected (e.g., Azerbaijan, Energy, Canada, Egypt, India, Mauritania and Senegal, the North Sea, and Trinidad and Tobago). Other companies that impaired gas or LNG assets include Woodside, Inpex, Santos, and Origin Energy.

Yet these impairment charges came alongside a flood of capital into the sector. Mozambique LNG closed a $14.9 billion financing agreement, while the Arctic-2 project in Russia is close to finalizing a $9.5 billion financing package—evidence that new projects can still attract capital from traditional sources (export credit agencies and banks). Berkshire Hathaway Energy announced a $9.7 billion acquisition of assets from Dominion Energy, including a stake in the Cove Point LNG facility; the company also acquired minority stakes in five Japanese trading houses, all of which have exposure to the oil, gas, and LNG sectors (Marubeni, Mitsubishi, Mitsui, Sumitomo, Itochu). Blackstone sold a stake in Cheniere Energy Partners for $7 billion to Brookfield. (Brookfield also acquired a minority stake in Cove Point last year.)

New Player in the East Med Faces a New Landscape

The bottom line: Monetizing the remaining resources in the East Med remains as challenging as ever. On July 20, Chevron announced it would acquire Noble Energy, one of the major players in Israel and Cyprus. The most obvious question raised by Chevron’s entry is whether the two projects that have long been delayed—the development of Aphrodite (Cyprus) and an expansion at Leviathan (Israel)—will now move forward, perhaps enabled by a greater risk tolerance, an ability to spend money, or improved capacity to overcome the complexities involved in big projects. But Chevron confronts a changing regional landscape: Cyprus will soon start importing LNG and is even advancing a plan to import electricity from Egypt. The domestic market in Israel is getting crowded by competitors. And new discoveries in Egypt make it harder to advance any agreement that sees more gas going into Egypt.

The backstory: On July 9, Cyprus broke ground on an import terminal, making it likely that the country will buy gas from overseas before it produces its own. Another project allowing Cyprus to buy electricity from Egypt took another step forward, as the developer received bids for the cables. (The end goal is to link Egypt’s power sector with Cyprus and then Greece.) In Israel, Energean is nearing the completion of its Karish project, and the company announced more sales contracts associated with the project, making it likely that most gas will stay in Israel rather than be sold abroad (the company has secured annual sales for 7 billion cubic meters, and the project’s capacity is 8 billion cubic meters). Meanwhile, Israel has increased its imports of LNG, taking advantage of historically low prices for spot LNG. In Egypt, Eni announced another discovery in the country, this time in the Great Nooros area.

Together, these developments underscore the challenges of developing the remaining gas in Israel and Cyprus. The domestic market in Israel is absorbing new sources of (cheaper) gas—how much more upside there is remains to be seen, given that reliance on renewables is growing as well. Cyprus is already looking for two ways to meet its own limited demand. And Egypt continues to make new discoveries that reduce the need for imports and that create a hope that its export capacity might be utilized fully based on domestic production rather than imports. These developments all create further pressure on the remaining resources in Israel and Cyprus to find new evacuation routes.

The Southern Corridor Comes into Shape

The bottom line: Southeast Europe, including Turkey, are absorbing more and more natural gas, but supply will grow further given a major discovery announced in the Black Sea and the addition of several infrastructure projects that will deepen regional connectivity. Meanwhile, the political relationships that underlie these trading arrangements are being tested by worsening relations between Greece and Turkey as well as by a possible conflict in the Caucasus that could create new insecurities about gas supplies.

The backstory: On August 21, the Turkish state-owned company, TPAO, announced a major discovery in the Black Sea, which could, in theory, produce anywhere between one-quarter to one-third of the country’s current gas needs. Such a discovery, if confirmed and proved viable commercially, will prompt Turkey to seek lower prices from its long-term suppliers. At the same time, the country faces a choice: should it use the domestic gas to displace imports or should it use it to displace and lessen the reliance on coal and other sources? The answer to that question will have regional repercussions.

The reason is that Turkey is increasingly becoming a corridor for gas into Southeast Europe. The Trans Adriatic Pipeline (TAP) that will bring gas from Azerbaijan to Southeast Europe via Turkey reported that it was 97.9 percent complete in the end of August. It is targeting first gas by the end of 2020. On the other side of the border, in Greece, Bulgartransgaz formally joined the floating regasification and storage unit (FSRU) that will be based in Alexandroupolis and is being developed alongside the Interconnector Bulgaria-Greece. That pipeline is expected online by July 2021. All this while LNG imports into Greece are growing due to low prices.

These flows and new projects create a greater interdependence between Azerbaijan, Turkey, Greece, Bulgaria, and Italy. Increased supply and connectivity should improve energy security and lead to lower prices—everything else being equal. But independence relies on trust, and growing tensions between Greece and Turkey could undermine that trust and politicize gas flows in ways that have not happened before (Greece has been buying gas from Turkey since 2007). Disruptions in the gas flow from Azerbaijan if the conflict with Armenia escalates could also bring energy security to the agenda—although, for now, it is only Turkey that would be affected materially since TAP has yet to start up.

Some Further Reading

• Cheniere, “Corporate Responsibility Report,” July 2020.


• Gazprom, Feedback on EU Methane Strategy, August 5, 2020.


• Erica Downs And Sheng Yan, “Reform Is in the Pipelines: PipeChina and the Restructuring of China’s Natural Gas Market,” Columbia Center on Global Energy Policy, September 16, 2020.


• Jean-Baptiste Dubreuil, Greg Molnár, Songho Jeon, “Fast-tracking gas market reforms,” International Energy Agency commentary, 12 September 2020.


• International Gas Union, “Wholesale Gas Price Survey 2020 Edition,” July 2020.

Nikos Tsafos is a senior fellow with the Energy Security and Climate Change Program at the Center for Strategic and International Studies in Washington, D.C.

Commentary is produced by the Center for Strategic and International Studies (CSIS), a private, tax-exempt institution focusing on international public policy issues. Its research is nonpartisan and nonproprietary. CSIS does not take specific policy positions. Accordingly, all views, positions, and conclusions expressed in this publication should be understood to be solely those of the author(s).

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