CSIS Gas Line, Q4 2019 [GGP]
Crisis Averted—Sort of
The bottom line: These past few months have shown that European gas security, in the old sense, is now largely a Washington obsession and a transatlantic issue. Russia and Ukraine reached an agreement before December 31, thus averting another gas crisis. At the same time, the United States imposed sanctions on Nord Stream 2, and Allseas, the contractor laying the pipeline for the project, suspended its operations. Yet prices at TTF, the main European hub in the Netherlands, averaged 37 percent lower in December 2019 than in December 2018—which did not exactly signal a crisis.
The backstory: The transit contract that allowed Russian gas to reach Europe through Ukraine was expiring on December 31, and this date has long been feared in Europe—any failure by the two sides to reach an accommodation could have disrupted gas flows to Europe. There were many issues complicating a settlement: Ukraine was hoping to bring its legislation in line with European rules; there were outstanding legal claims between the two sides; for a few years, Ukraine had ceased to buy gas from Russia directly; the prospect of Nord Stream 2 and TurkStream hung over the proceedings, a reminder that Ukraine’s transit role was likely to shrink over time; and, of course, hostilities between the two countries were ongoing, just as a new president in Ukraine became the focal point for the impeachment of President Trump.
Yet the two sides were able to reach an agreement (supported heavily by Maroš Šefčovič of the European Commission, as well as by individual member states like Germany). The deal provides for minimum transit volumes of 65 billion cubic meters (bcm) for 2020 and 40 bcm per year for 2021-2024; Gazprom paid Naftogaz $2.92 billion to settle the arbitration awards of 2017 and 2018; and the two sides dropped all other legal claims (they did not agree on any future gas supply, and they also did not resolve any issues related to asset seizures in Crimea).
While this negotiation was taking place, sanctions on Nord Stream 2 were included in the National Defense Authorization Act for Fiscal Year 2020, leading Allseas to suspend operations. What this means for the project is unclear—Russia claims it has the capacity to finish the project, but it is too soon to tell whether this is true or what delay there might be anyway. The reaction from Germany has been stern, but, again, it is too soon to tell how this will play out and how far Germany will seek to retaliate for what it deems as an interference in European affairs.
But the overarching conclusion, looking at European gas in late 2019, is that Europe seemed secure, confronting a possible major crisis with diplomacy and calm, benefiting from a decade of reforms, and money spent, to buttress its defenses. Russia and Ukraine reached an agreement that acknowledged a smaller guaranteed role for Ukraine, with a possible upside. The grid in Southeast Europe is already changing to accommodate TurkStream (and gas from Azerbaijan). The countries most worried about Russia are putting the final touches in their defenses. So this battle for European gas looks like it moved from an actual concern about how gas flows in Europe and into a transatlantic fight between Germany and the United States.
The East Med Diverges
The bottom line: In this quarter, two contrasting worlds in the East Med diverged further. The East Med region should be best understood in two parallel worlds: in the domain of actual production, gas pipelines, trade flows, dollars invested, and so on, there is an emerging cluster that includes Israel, Jordan, and Egypt, which Cyprus might one day join (likely as an exporter to Egypt). Meanwhile, there is a world of highly combustible political tensions emerging, with Turkey at its epicenter, but involving Greece, Cyprus, Libya, and external forces like the European Union, the United States, and Russia.
The backstory: On December 31, Noble Energy (United States) announced first gas from the Leviathan field in Israel, reaching another milestone in a journey that started almost nine years ago (the initial discovery was announced on December 29, 2010). It was a busy quarter for Noble and its partners: in October, they amended an agreement for supplying gas to Egypt, and in November, they closed the transaction to acquire a 39 percent stake in the EMG pipeline, which had previous flowed gas from Egypt to Israel; they also signed an agreement for the first exploitation license in Cyprus, crossing another hurdle for the development of the Aphrodite field (via pipeline to Egypt).
The launch of Leviathan is a transformative event for East Med gas: rather than gas flowing primarily within countries, it will now flow between them, with a sizable trade emerging between Israel, Jordan, and Egypt. At the same time, the surge in production in Egypt has created a need to find outlets for excess gas, with production at Zohr now “capped.” In Jordan, gas from Israel will compete with liquified natural gas (LNG) as well as pipeline exports from Egypt. So the first large-scale cross-border flows will bring their own challenges, both commercial and political. How this plays out remains to be seen.
While these developments took place, there was a somewhat parallel world emerging nearby. Turkey signed an agreement with the internationally recognized government in Libya to delineate the maritime border between the two countries, drawing rebuke from most others in the region. Meanwhile, the National Defense Authorization Act for Fiscal Year 2020 contained provisions related to the region—chiefly, it lifted an arms embargo on Cyprus, and it limited the transfer of the F-35 to Turkey, cementing a perception that the United States is moving away from a reliance on Turkey as a core partner in the region (but the final language did not include the energy provisions of the Eastern Mediterranean Security and Energy Partnership Act of 2019). On January 2, 2020, Greece, Israel, and Cyprus signed an intergovernmental agreement for the East Med pipeline, alongside a preliminary agreement between two companies for gas sales into the pipeline, although neither development changes the challenging prospects for this project.
All these developments do not fundamentally alter the energy dynamics in the region, which are mostly playing out further east. In fact, during this quarter, Cyprus authorized the construction of an LNG import facility, while there was also a push by Energean to sell pipeline gas from Israel to Cyprus—both evidence that the center of gravity of actual developments remains away from the more volatile politics emerging between Greece, Turkey, Cyprus, and global powers active in the region.
Positioning for the 2020s
The bottom line: We are headed toward a supply boom in the mid-2020s, with possibly dramatic implications for prices, trade flows, and energy security, and that market development, in whatever form, will be essential to allow all this new gas to be absorbed. The race to develop new LNG supply continued in Q4 2019 with one project taking a (soft) final investment decision (FID), and several other projects positioning for FID in 2020. In all, these developments reinforce a reality discussed in earlier versions of Gas Line: that a supply surge is coming.
The backstory: One LNG project announced a final investment decision (FID) in Q4 2019: an expansion at Nigeria LNG. However, the press release noted that “the award of contracts for the engineering, procurement and construction activities to follow the closure of bank and Export Credit Agency (ECA) financing, and the finalization of some key supporting commercial agreements expected in early 2020.” Given that only one foreign partner released the customary press announcements following this milestone, this might be understood as a soft FID, with a more definite announcement coming in 2020. Either way, however, this was a record year for LNG FIDs—and there is more coming in 2020.
The most significant news, in terms of new supply, came from Qatar Petroleum which, once again, upsized its proposed North Field expansion project, now to 126 million tons by 2027, a 64 percent increase relative to today (the previous target was 110 million tons). Given the existing industrial footprint in the area, and the liquids associated with the gas production, Qatar is widely seen as the lowest cost producer worldwide—so this is an effort to signal to the market that Qatar is willing to compete for market share (no matter what the price).
In Australia, Woodside increased its estimated resource estimate at Scarborough by 52 percent. The company meanwhile executed a sales and purchase agreement with Uniper, with the volumes rising if FID is made on Scarborough, and it agreed on a tolling price with BHP to process gas at the Pluto facility. At the same time, it took FID on a pipeline connecting its two facilities in Northwest Australia (Pluto and Northwest Shelf). In all, these are signs of definite progress toward FID (which the company is targeting for the first half of 2020)—and underline a key point made in an earlier Gas Line: do not write off Australia.
In the United States, the Federal Energy Regulatory Commission (FERC) approved four projects in November, further boosting the potential candidates for FID in 2020. The Lake Charles project, developed jointly between Energy Transfer and Shell, announced the launch of a commercial tender for engineering, procurement, and construction services. The Commonwealth LNG project entered into a deal with Gunvor that allows the later offtake from the project, as well as help in marketing the remaining volumes. And in Alaska, a joint venture that includes a company headed by the former lieutenant governor proposed to build an LNG export facility in the north, thus avoiding the costs involved with constructing a pipeline across the state.
Elsewhere, Novatek (Russia) secured a license that will help underpin its proposed Arctic LNG 1 project. In Myanmar, Woodside and its partners announced a fiscal agreement with the government, which furthers the odds that the A-6 project will be developed. BP and its partners announced more gas found offshore Mauritania and Senegal, meaning that the more LNG might eventually come from that part of the world.
On the demand side, Vietnam may have started construction on its first LNG import terminal, while AES Corporation (United States) was granted approval for a gas-fired power plant in late September. Vietnam may thus finally become an LNG importer. In Thailand, Mitsui (Japan) said it was going ahead with a 2.5 GW gas-fired power plant. In India, Total (France) announced a partnership with the Adani Group that will enable the company to contribute to India reaching its ambitious targets for gas use. In Panama, the Colón import facility officially started operations, while the first-ever gas-to-power project in El Salvador finalized its project financing arrangements.
But it was not all good news for prospective importers. In the Philippines, a proposed import project hit a snag when one of the primary sponsors acquired a stake in the largest existing field in the country. And in Australia, a proposed project by ExxonMobil has received lukewarm interest by local industry for long-term commitments.
Strong Momentum for LNG Bunkering
The bottom line: There is growing momentum for using LNG in ships. The International Maritime Organization (IMO) has set a 2050 target to reduce CO2 emissions from shipping by 50 percent relative to 2008. Combined with IMO 2020, a rule that limits sulfur emissions, there has been growing impetus for using LNG in ships. In fact, even in a deeply decarbonized world, LNG use in ships should grow, since it competes favorably with many of the existing alternatives for reducing air pollution and CO 2 emissions. At the same time, increased use depends on investment and support by vessel owners and operators; by ports; by host governments; and by gas suppliers to provide the gas—and so individual investment decisions and strategies become crucial in discerning how big this prospective market will be.
The backstory: This quarter saw plenty of news to support a more bullish view of the role that LNG can play in marine transportation. Total made a lot of news: it launched its first LNG bunkering vessel, which will operate in Northern Europe; it signed a long-term charter for a second LNG bunkering vessel to operate in southern France; it signed an agreement to supply LNG for 10 years to CMA CGM (France), one of the world’s large container companies; and it finalized a deal with Pavilion (Singapore) to jointly operate an LNG bunkering vessel in Singapore.
Mitsui O.S.K. Lines (MOL/Japan) announced in December that “it has signed its first green loan, the proceeds of which will be used to partially finance the construction of the world's largest LNG bunkering vessel, which will be owned and operated by MOL.” BHP, which had announced in July a tender for carrying up to 10 percent of its iron ore using LNG-powered ships, is reportedly close to making a final decision on that tender.
The cruise industry, which has been a pioneer in adopting LNG bunkering, saw another major delivery, this time to Costa Cruises, a brand of Carnival Corporation. This is Carnival’s second LNG-powered ship, and the company “has an additional nine next-generation LNG-powered cruise ships on order using the company's innovative environmental design, with expected delivery dates for these new ships between 2020 and 2025.”
The Arctic is emerging as another hotspot for LNG-powered vessels. In October, Sovcomflot (Russia) reported two crude oil vessels making an eastbound journey powered exclusively by LNG, following the first such voyage in September. The company reports that it has “six LNG-fueled oil tankers in operation, all delivered in 2018-2019,” a sure sign that it sees growth in this area (and a way to absorb LNG volumes produced in the Arctic).
Defining the Future Gas Grid
The bottom line: There is a growing focus on how existing gas grids can help with the transition to low-carbon energy. In a low-carbon world, gas used in buildings will need to be phased out, and this fact is slowly morphing into a mini-battle between those who want to electrify everything and those who think the current gas networks can carry renewable gas or hydrogen. This tension is slowly manifesting itself in policy—with several cities looking to ban new buildings from connecting to the gas grid; but it is also being fought in the research arena, with studies exploring the potential for building electrification or heat pumps for instance.
The backstory: Over the past few months, there has been a flurry of research into the role of gas infrastructure in a low-carbon energy system. One long-term option, of course, is to electrify buildings (and perhaps industry) and thus gradually phase out existing gas networks. But there is also a strong case for repurposing networks to carry renewable gas or, eventually, hydrogen. There were several reports published this quarter alone, which sketched out what that future might look like.
In its latest World Energy Outlook, the International Energy Agency (IEA) devoted a chapter on gas infrastructure, forecasting that in its Sustainable Development Scenario, “Low-carbon gases make up 7% of total gas supply globally in 2040 – and is [sic] on a steep upward trajectory.” The IEA outlined a future that combined both biomethane and hydrogen, and also presented a high-level supply curve for biomethane (showing prices considerably higher than conventional gas). Crucially, the IEA underscored the need to “broaden the regulation of gas networks to take account of the transition to low and zero carbon energy.”
This was also, in a nutshell, the theme of a new study by the European Network of Transmission System Operators for Gas (ENTSOG). ENTSOG’sRoadmap 2050 for Gas Grids report outlined a regulatory agenda for thinking about how gas grids might evolve. It contains dozens of recommendations, from aligning the frameworks for gas and power, to offering a regulatory sandbox to explore innovations, to ensuring proper remuneration for gas handling between networks—and many more. If there is a single document to outline how gas grid operators are thinking about the future, this is it.
In Australia, the government released its long-anticipated hydrogen strategy, which explored, among other things, the opportunity to inject hydrogen into existing gas networks, but also addressed the case for relying on hydrogen, instead of electrification, to replace gas. One interesting nugget: “High level modelling of two pathways to decarbonise Victoria’s gas consumption – full conversion to renewable electricity for existing uses of electricity and natural gas, and the use of hydrogen as a means of decarbonising gas use – suggests that replacing natural gas use with hydrogen using existing infrastructure may be up to 40% less expensive than full electrification.” If nothing else, this observation outlines how much of the case for hydrogen might rely on utilizing existing gas networks.
The Oxford Institute for Energy Studies also released a study in October on renewable gas in Europe. It, too, explored the differences between biomethane and hydrogen and their possible roles in Europe’s energy future. Perhaps the most important insight was the understanding that biomethane is both expensive but also relatively mature: “With nearly 500 biomethane plants in operation across Europe, this can be considered mature technology, although some further modest cost savings may be achievable.” Hydrogen, by contrast, is an emerging technology whose cost structure will evolve considerably. The future of the two, therefore, should really be understood in separate terms.
Finally, the American Gas Association released a study, prepared by ICF, on the supply and emissions reduction potential from renewable sources of natural gas, including landfill gas, animal manure, food waste, and others. The study evaluated nine different feedstock sources and three production technologies. On market potential, the study found that renewable gas could scale up, by 2040, to a level near current residential gas consumption. On costs and mitigation potential: “ICF estimates that the majority of the RNG produced in the high resource potential scenario is available in the range of $7-$20/MMBtu, which results in a cost of GHG emission reductions between $55/ton to $300/ton in 2040.”
The statements, opinions and data contained in the content published in Global Gas Perspectives are solely those of the individual authors and contributors and not of the publisher and the editor(s) of Natural Gas World.