Gas Line Q3 2019
October 1, 2019
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:
A Record Year for FID—With More to Come
The bottom line: It is now official that 2019 will mark a record year for final investment decisions (FID) in new liquefied natural gas (LNG) supply. With three months still to go in the year, and even though several high-likelihood projects have yet to take FID, there is more upside to the year and more coming in 2020. Clearly, supply is not waiting for demand. It is plunging ahead, with projects advancing all over the world, which means either prices will be depressed in the future or suppliers will have to work harder to create demand (by investing in infrastructure, by taking more risk, or by lowering prices—more on that below).
The backstory: Two projects announced a FID in Q3 2019: the Calcasieu Pass facility in the United States and the Arctic 2 project in Russia, bringing the total LNG capacity sanctioned this year to almost 63 million tons per annum. This number is not only a single-year record, but it is also double the amount sanctioned annually during the previous supply boom (from 2011 to 2014). Even accounting for the relative drought in 2016 and 2017, the pace of new investment is staggering.
Even so, the supply wave is far from done, and the attention now shifts to the next tranche of projects that have a high likelihood to take FID in the next 15 months. On top is, of course, Qatar’s expansion plans, with Qatar Petroleum (QP) having shortlisted a few international firms as possible partners for the next phase in the country’s LNG development. What is less clear is how the partners might be chosen (if partners are selected at all). One option is to find companies that can offer QP access to international assets, expanding the company’s growing overseas footprint. Another is to find partners that will guarantee access to markets. Or, Qatar may choose to make a geopolitical statement by selecting partners from great powers, hedging its reliance on the United States. Either way, this is the most anticipated decision in the LNG market today.
Beyond Qatar, several projects made news this quarter. In Indonesia, Inpex announced that the government approved its proposed plan of development for the Abadi LNG project. In Nigeria, the long-awaited Train 7 project received a modest boost when Nigeria LNG signed a letter of intent with the engineering, procurement and construction contracts, with sponsor Total saying it intends to take FID this year. In Papua New Guinea, the proposed Papua LNG project went through a roller coaster as the new prime minister signaled an intent to renegotiate a deal with foreign companies before pledging to honor the initial dear after some concessions were reportedly offered—promising, instead, to drive a harder bargain on the next round of negotiations. In Australia, Woodside signed a preliminary agreement to sell LNG to Uniper, bolstering the odds of expanding the former’s Pluto facility in Australia. And Novatek is already thinking about its next LNG project.
In the United States, Freeport said that it had secured sufficient financing to expand its facility (Train 4). Cheniere Energy announced another innovative deal, this time with EOG Resources. EOG committed to sell some gas to Cheniere at a price linked to Henry Hub while offering another supply tranche linked to international LNG prices (the Japan Korea Marker). In this way, Cheniere is further tying its gas purchases to global LNG prices while also firming up its gas feed through long-term contracts with U.S. producers. If anything, this dual structure reinforces the complexity in how gas prices are evolving explored in the previous edition of Gas Line.
Other U.S. projects announced preliminary agreements as well. Tellurian signed a second memorandum of understanding with India’s Petronet (following one in February) this time specifying that the transaction might be “up to” 5 million tons per annum. Magnolia LNG announced a preliminary agreement with a private power plant developer in Vietnam, a sign of how U.S. developers are pushing at the frontiers of the LNG market to secure customers. AES also announced that it received government approval for a proposed gas power plant in Vietnam, which could help anchor an import terminal. On that front, the Export-Import Bank of the United States said it was studying how it could help U.S. LNG developers, although no details have emerged so far on what structure would be pursued (EXIM meanwhile authorized a loan of up to $5 billion for the Mozambique LNG project).
One project made news this quarter not for its progress but its apparent backsliding: Alaska LNG (AK LNG). The Alaska Gasline Development Corporation, the state agency shepherding the project, said in July that it was downsizing its staff, reducing its emphasis on advancing the previously outlined commercial structure, and focusing, instead, on securing environmental permits. The move was not a surprise—the project’s structure has been in flux since a new governor was sworn in last December; but it was soon followed by an announcement that BP, which owns a big share of the reserves that would feed AK LNG, would sell all its Alaska assets to Hilcorp. In short, the project is back to the commercial drawing board just as it continues to advance through the Federal Energy Regulatory Commission process.
Suppliers (Sort of) Moving Downstream
The bottom line: As LNG supply is set to boom, there are several potential markets that still lack the necessary import infrastructure for LNG. When confronted with such obstacles in the past, LNG suppliers have invested downstream and help build that infrastructure. There is some evidence that they might be interested to do so again, potentially unlocking a whole new market for LNG.
The backstory: The LNG market was mostly developed in a fragmented way: producers built export infrastructure (liquefaction), utilities built import infrastructure (regasification), and someone arranged for shipping. There was cross-pollination, of course, chiefly when companies from importing countries, say Japan, took equity stakes upstream, but few suppliers invested heavily to create import infrastructure—if anything, it was the consumers who helped create supply.
In the 2000s, this pattern changed, and suppliers invested heavily in import infrastructure. Qatar Petroleum (and its partners) took equity stakes in new import terminals in the United Kingdom, Italy, and the United States. The first import terminal in China, which opened in 2006, involved a foreign co-investor as did the first import terminal in India, which came online in 2005. Angola LNG built its own terminal in the United States, and several major suppliers reserved capacity at new or existing facilities in order to ensure an outlet for their gas. Selling gas meant building some infrastructure in receiving countries for that gas to enter new markets.
In the 2010s, the pendulum swung back again. Import infrastructure was created without significant supplier participation. Most of the countries that started to import LNG after 2010 did so by relying on local companies, not foreign firms, to undertake the investment necessary—few projects had foreign investors at all, and fewer still involved foreign suppliers whose main motivation in joining the project was to secure a market for their gas. Eventually, suppliers even sold their stakes in import facilities as they saw greater returns upstream. The upstream and the downstream was effectively severed.
As long as importers could develop the requisite infrastructure, this hands-off supplier approach made sense. But the world is now headed into a market with ample forthcoming supply, courtesy of a record level of FIDs, facing prospective importers that have struggled to execute on long-standing plans to construct import terminals (e.g., Vietnam, the Philippines, South Africa) or countries where there might not be a strong anchor customer locally to underpin a new import project (e.g., Myanmar). The question is: will suppliers get back in the import business?
There is some evidence this might be happening. Companies have been keen to develop new markets, with LNG bunkering in particular continuing to attract interest (both Shell and Total made announcements this quarter about investments in bunkering). On the regasification side, Total announced in July that it would help develop an import terminal in Benin and reportedly took an equity stake in the Dhamra terminal in India. In Pakistan, both ExxonMobil and Shell were among the companies short-listed to bid for constructing new import facilities. And Japan made news again by renewing a commitment to help build LNG import infrastructure in Asia.
It is always hard to gauge what these moves will amount to—this is often as much about exploiting an immediate opportunity rather than a big strategic thrust, and despite the announcements, most import infrastructure is still being developed without supplier participation. But any move to accept the risks involved in building import infrastructure would be a major development for the market and could help absorb what is starting to look like an excess of the supply in the mid-2020s.
More Efforts to Boost LNG Transparency
The bottom line: Gas pricing is experiencing a multiyear and multidimensional evolution from a system based largely on oil indexation into something new. I have written about that evolution in previous pieces as well as the last Gas Line. This quarter stood out for the technical innovations it involved—with three major new initiatives promising to boost transparency and liquidity, and thus adding to the momentum towards a new pricing system for gas internationally.
The backstory: In July, Platts and the Intercontinental Exchange (ICE) announced they would launch an electronic window for spot LNG sales, allowing participants greater visibility in the transactions taking place in the spot market—and already, the window is getting some use. In August, BP published its standard master sales and purchase agreements (MSA) that it uses for LNG sales, thus creating a useful benchmark that can cut down on transaction costs. And in September, CME Group announced it was launching the first futures contract for U.S. LNG exports with physical delivery at the Sabine Pass facility in the Gulf of Mexico. The fact that so many undertakings took place in a single quarter is a testament to two realities: First, there is rapid change in gas pricing. Second, there is still an enormous amount of experimentation as market players are looking to find the best way to price gas. We might be leaving oil indexation (slowly), but it is still not clear where we are going.
How the Glut Played Out
The bottom line: The past few months have witnessed an unprecedented glut, leading to an all-time low price at the Title Transfer Facility (TTF) in the Netherlands and to record low prices in Asian spot LNG. The main question in the last Gas Line was how the market would react. Now we know: prices fell to very low levels; demand in Asia did not respond to these low prices; no supplier cut back output, either to stop losses (e.g., U.S. LNG) or to prop up prices (e.g., Russia); gas was pushed into Europe, triggering both a rapid buildup in stocks, and some high levels of fuel switching as cheap gas pushed out coal—but only in select markets. Elsewhere, gas showed no gains at all, raising important questions about the price elasticity of demand in Europe.
The backstory : For most of 2019, the dominant story in global gas markets has been the unprecedented rise in LNG supply coupled with weak demand for LNG, especially in Asia. Prices at TTF reached an all-time low on June 28 before recovering somewhat (at the end of September, prices have risen almost 30 percent relative to that low point). The supply response was limited: despite fears that low prices might force U.S. LNG exporters to cut back deliveries, U.S. LNG exports have kept growing, with no off-takers curtailing their commitments. Russia’s exports fell, though in part because 2018 was a record year. But there was no widespread reaction to low prices on the supply side.
On the demand side, the story was mixed with several important dynamics seen in Europe, which was the main destination for surplus gas. In some markets, cheap gas led to a surge in demand for power largely at the expense of coal. In Spain, for instance, gas generation rose 40 percent in the first half the year, while coal-fired generation declined by over 40 percent. The numbers in Greece were similar: gas was up 28 percent and coal was down 16 percent. The Netherlands showed a similar trajectory with the growth in gas largely mirroring the decline in coal.
By contrast, in Germany, there was a sharp drop in coal generation, but it was driven by wind not gas (which still grew by 12 percent, but nowhere near enough, volumetrically, to explain the loss in coal). In France, gas rose largely due to weak hydro not cheap gas prices; in Turkey, gas use fell because hydro was very high; and in the United Kingdom, gas-fired generation was flat. In short, the European response to cheaper gas was highly uneven and depended on country-specific factors. The surge in LNG imports helped push storage to be nearly full, even though gas demand in European members of the Organisation for Economic Co-operation and Development was up just 1.6 percent in the first half of the year, when TTF averaged just $5.30 per million British thermal units (it hovered below $4 during Q3). All this to say—cheap prices are not enough for gas to automatically gain market share.
Europe’s Inability to Transcend Gas Geopolitics
The bottom line: The European gas market is consumed by a single question: will there be a new transit deal between Gazprom and Ukraine before December 31 in time to avert another disruption to supplies this winter? The odds of success seem improved as Gazprom’s preferred alternative, to have both Nord Stream 2 and TurkStream running, seems impossible, and with Nord Stream flows curtailed as well, Ukrainian transit is indispensable for now. But the strategic impasse remains: Russia does not want to make a big, multiyear commitment to Ukrainian transit, while Ukraine, the European Commission, and the United States all want it to. That will be a hard square to circle. More importantly, Europe increasingly faces the contradictors in wanting an energy market that is both rules-based but also outcome-based. This past quarter showed those contradictions in full swing.
The backstory: The transit contract between Gazprom and Ukraine expires on December 31, and absent a new agreement, flows to Europe would be disrupted on January 1, 2020. The negotiations between Gazprom and Ukraine are multifaceted, but they have been affected by several external forces. First, on the market side, European storage is nearly full—driven in part by low LNG prices but also by a desire to protect against a possible interruption in supplies through Ukraine. Even Ukraine has built up a storage buffer, which can be used to meet its own demand. Ample LNG supply has also contributed to a calmer-than-average attitude toward the transit talks. At no point has Europe been readier for a supply disruption.
Second, Gazprom’s race to complete Nord Stream 2 and TurkStream has hit a few snags. Nord Stream 2 has yet to receive a permit by the Danish government, and the ongoing negotiations could reportedly delay the project by up to eight months. Meanwhile, in July, the U.S. Senate Foreign Relations Committee passed a bill targeting Nord Stream 2, although the bill still needs to pass the full Senate (and House) before it reaches the president for signature. And, of course, the negotiations about restructuring Nord Stream 2 to make it consistent with the Third Energy Package have yet to yield a breakthrough—and, in fact, Nord Stream 2 announced in July that it was challenging the measures in court, claiming they are discriminatory, and launched a formal suit in September. All this to say, Nord Stream 2, which was 75 percent complete in August, will still need to surpass several hurdles before it can start flowing gas.
Third, on September 10, the General Court of the European Union annulled an exemption granted to the Opal pipeline, which connects Nord Stream to the German-Czech border, to allow Gazprom to fully utilize the pipeline. The rationale was based on the principle of solidarity—that, in effect, Gazprom fully utilizing Opal harms Poland (the petitioner in this case). The effect was immediate, with Gazprom lowering flows through Nord Stream and increasing flows through Ukraine.
Interestingly, the Court did not find that the Opal exemption actually hurt Poland; it found that the exemption decision should have taken Poland’s interests into account, and that by not doing so, it breached the principle of solidarity. How this plays out will be interesting. Nord Stream lowered gas transit through Ukraine, but it has not affected flows through Poland, which claims to be hurt by the exemption, and the gas from Nord Stream ultimately helped Ukraine access Russian gas without having to buy it from Gazprom. The Court itself recognized that impacting other countries might not be a sufficient rationale—after all, any country that wants to diversify its gas sources might affect the neighbors on which it might depend for gas transit.
Europe, therefore, finds itself in a peculiar position. In Ukraine, it is seeking to convert a political relationship into a market relationship governed by European law, yet it is also trying to secure a multiyear commitment for gas transit that is driven largely by politics not market forces. In Opal, it is opting to keep half-empty a pipeline in order to protect the interests of a party that is not obviously hurt (Poland), enforcing the principle of “third-party access” to a pipeline that is connected to just one other pipeline and that, therefore, no third party can access—all to uphold the principle of solidarity that will be hard to define and delineate in practice. It is trying to do the same in Nord Stream 2—pushing for implementation of the Third Energy Package without being able to show an obvious market benefit from applying these rules, especially given that Gazprom has an export monopoly for pipeline gas from Russia, and thus, no third party can send gas through Nord Stream 2. And all the while, several European countries are petitioning the United States to help settle an intra-European dispute by levying sanctions against Nord Stream 2.
In a way, these events show that European energy security is backsliding—somewhat unable to fully endorse markets and still addicted to geopolitical micromanaging. A decade ago, the idea was that market rules could improve energy security. This they have clearly done. But the rules were never designed to limit Russian exports to Europe even though countries are supposed to diversify their import infrastructure. So here we are, two giant forces pushing against each other—a desire to have a rules-based market clashing with a desire to prevent the most commercially advanced player from capturing a large share of that market. This inherent contradiction, played out in legal, political, diplomatic and commercial battles that continue to define European gas, obscures the uncomfortable truth that the greatest threats to European gas security are still the internal barriers that prevent gas from flowing freely, not Russia.
Some Further Reading
- Akos Losz and Jonathan Elkind, “The Role of Natural Gas in the Energy Transition,” Columbia University, Center on Global Energy Policy, September 24, 2019.
- International Energy Agency, The Role of Gas in Today's Energy Transitions, July 2019.
- International Energy Agency, Global Gas Security Review 2019, September 25, 2019.
- National Energy Technology Laboratory, Life Cycle Greenhouse Gas Perspective on Exporting Liquefied Natural Gas from the United States: 2019 Update, September 12, 2019.
- Oxford Energy Forum, LNG in Transition: from uncertainty to uncertainty, September 2019.
- S&P Platts, New horizons: The forces shaping the future of the LNG market, July 2019.
Nikos Tsafos is a senior fellow with the Energy and National Security 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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