2019 was a record year for Liquified Natural Gas (LNG) producers and shippers. Global demand continued to grow strongly, 12.5% from 2018, to a record 359 million tons. Imports grew mostly to Europe, but also to South Asia. Relative newcomers to LNG imports, Bangladesh, India and Pakistan imported a collective 36 MT. Consumption in China, the third largest importer after the UK and France, grew 12%, continuing to outstrip domestic production growth. The year-to-year increase in trade, at 40 MT, was itself another record, and brought the increase for the last four years to 95MT, meaning the LNG market had increased by almost one-third in only three years. The spot LNG market, which facilitated flexibility in sales compared to standard long-term contracts, had grown from just over 10% of the market at the beginning of the decade to nearly 1/3 of all sales. The market had grown so attractive that the rush was on to jump in: 30 MT of new capacity came on stream in 2019 – on top of 100 MT from 2016 to 2018, and financing for 71 million tons of new capacity reached FID. Meanwhile on the domestic side in the US, natural gas continued to be attractive as a source of supply for new power plants as coal capacity is being phased out – with gas now being far cheaper than coal. Of the last 29 GW of coal power generation retired, 23 GW have been replaced with natural gas, especially in the large PJM interconnect market.
2020, after the record 2019, could have hardly have come as a bigger shock for the gas industry. Thanks to COVID-19, 2020 will see the largest annual drop in energy investment in history: 20%, according to the International Energy Association. The projected drop in investment in oil & gas is even larger, 33%, and after the record 2019 for new LNG FID decisions, the expectation for 2020 is… zero. Natural gas prices have been hovering around historical lows of $2/MMBTU. Oil prices have shown some recovery, after the Saudi Arabia-Russia deal to curb surpluses, but the global gas market remains extraordinarily oversupplied. With LNG storage nearing capacity, as happened in April for oil, the worst is likely still to come, and negative prices for LNG cargoes late this Summer cannot be ruled out. Unlike the oil market, there’s been no sign of a coordinated response to address the glut, meaning the fallout could be deeper and longer. For the fracking-focused companies in the US, the outlook was already grim, and it is only getting worse: in 2019 42 E&P companies filed for bankruptcy, involving over $25B in debt. Moody’s noted “We are seeing slowdowns and negative cash flows spill over into the oil services sector that relies on the E&P companies for their business, and heavy hitters such as Schlumberger and Halliburton recorded significant losses in 2019.”
So what’s next?
Optimism has been ruling projections of the future of natural gas for several years. With the increased production from the development of new E&P technologies, and a vast increase in investment in transport capacity, natural gas became cheaper than all other fossil fuels – including coal – and far more widely available than before. With growing concerns over carbon emissions and climate change, gas also benefitted from being seen as better than coal on the environmental side. Forecasts at the end of 2019 projected a near-doubling of global LNG demand from 2018 to 2035 (McKinsey, Shell), outpaced by even faster growth in supply – excess supply was expected to keep prices low into the mid-to-late 2020s. In the US, a 20% growth in demand from the power sector was seen by 2025, and the industry announced plans for some $30B in new interstate pipelines over the next five years. Only the production end, as noted above, was seen as facing continued difficulties.
Optimism is now on hold, pretty much across the board. In one year, LNG prices in Asia – the highest in the world — plummeted from $12/MMBTU to $2/MMBTU. Courtesy of the IEEFA, here is a list of the LNG projects put on hold or cancelled in the last three months:
• March: Santos-Barossa/Darwin (Australia); Sempra-Costa Azul/Port Arthur (Mexico-USA); Woodfibre (Canada); Woodside Energy – Pluto Train 2 (Australia); Shell/ETP – Lake Charles (USA); Magnolia LNG and Bear Head (USA-Canada)
• April: Qatar Petroleum – North Field East (Qatar); Shell Crux (Australia); Exxon Rovuma (Mozambique); Golar/BP Grande Tortue (Mauritania and Senegal); Pieridae/ Goldboro (Canada)
McKinsey’s annual natural gas outlook for 2019 had noted that of the 100 projects potentially planned to add new LNG capacity, each would need a maximum full break-even price of $7 per million British thermal units (MMBTU) to stay competitive: more than three times current prices in Asia – the “strongest” LNG market, with prices possibly heading still lower.
For the US power market, probably the largest user gas user, forecasts from the EIA have now shifted significantly. In 2019 the EIA had estimated natural gas would be the largest segment of the US power market until well beyond 2050, with an 8% higher share than renewables even in 2050. The new 2020 EIA outlook instead sees renewables with a 2% higher share than gas by 2050. Interconnection queue requests across all the major North American markets show that over 90% of new requests now consist of solar, wind and storage. This is spite of gas prices not only being low being getting even lower. The problem? A combination of costs and policy. From a cost standpoint, the fall in natural gas prices is being paralleled by continued technology improvements and falling costs for wind, solar, and energy storage. The cost declines of wind and solar, being technology-driven, are unlikely to reverse themselves, whereas the cost of declines of natural gas, now being driven by supply-demand imbalances, have an unpredictable future. From a policy standpoint, the “climate honeymoon” of natural gas has waned, if not ended. Three converging environmental trends are working against natural gas: (1) growing concerns on the climate front, as this week’s news indicate that even lower emissions during the COVID epidemic do not seem to have reduced atmospheric carbon levels, and climate change projections continue to get worse; (2) new studies of methane leaks are increasingly raising estimated average emissions from natural gas related projects, making natural gas now seem only marginally better than coal on the emissions side, and far less preferable than renewables; (3) studies on fossil fuel pipeline environmental effects are also raising the level of concern of damage from natural gas transport (a study of the 2010-2018 period in the US documented more than 5,500 total pipeline incidents, more than $4 billion in damages, and evacuations of almost 30,000 people – with a strong and unexpected correlation between the number of problems and how new the pipelines were). A number of US cities (San Jose is the largest) and utilities have moved to impose bans on new natural-gas infrastructure. Even existing gas power plants are becoming policy conversation targets, for possible replacement by cheaper renewables: in mid-2018, already, GE closed a $1B natural gas plant in southern California only 10 years into a planned 30-year life. Even the more politically conservative Midwest has seen regulators decline to endorse new gas-fired plants. In Europe, the European Investment Bank (EIB) announced in November that it will stop backing fossil fuel energy investments, including natural gas, in 2021 unless they negate their emissions through carbon capture or offsets.
The answer to what’s next for gas is, well, not much fun. At least for gas exploration, production, and transport companies. On the one hand low prices are likely to persist, which will lead to an increased number of bankruptcies in the E&P sector, and keep investors in LNG liquefication, transport, and gasification on the sidelines for any new projects, possibly into the middle of the decade. In the short-run, existing importers using spot prices (and not locked into long-term contracts) will see a windfall of cheaper gas imports. Importers locked into long-term contracts at higher prices may well take the opportunity to push for downward price renegotiations from suppliers, and in some cases possibly even walking away from contracts: when the contracts were entered into, accessing natural gas supplies looked difficult, in the future this is unlikely to become the case again anytime soon. The decades-long seller’s market is now a buyer’s market, for the foreseeable future. Good for users, but making it even worse for producers. Policy concerns in Europe and the US on emissions will likely keep dampening demand in a way that previous projections had not captured. This will leave Asia as increasingly the only attractive market for sellers. For the power sector, “peak gas” may arrive very soon, at least outside of Asia. In turn, expect natural gas suppliers to become more dependent on non-power demand, where electrification will take longer to materialize. That 100% increase in global LNG demand over the next two decades forecast at the end of 2019? It may have a hard time reaching 50%.
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