U.S. liquefied natural gas (LNG) developers are anticipating that 2021 will be much different than 2020.

Covid-19 and uncertain long-term economics dashed the plans for a number of U.S. gas export projects to make a positive final investment decision (FID) this year. Most of those projects pushed their planned FID dates into 2021, with the expectation of coming online by the middle of the decade to meet what is expected to be global supply shortage. 

With vaccinations beginning, global gas demand is expected to rise, but the long-term profitability of U.S. LNG is still an open question. Arbitrage opportunities to Asia and Europe have decreased since the first wave of domestic projects was funded in the previous decade.

The International Energy Agency said in October global gas demand would likely fall 3% in 2020 to 3.88 trillion cubic meters, or 375 Bcf/d. And the International Gas Union in August said LNG consumption in 2019 totaled a gas equivalent of 482 billion cubic meters, or 46.6 Bcf/d. It added that LNG use could fall about 4% this year but then rebound quickly in 2021, depending on the persistence of the pandemic.

Meanwhile, Wood Mackenzie predicted in September that global LNG demand would continue to grow to 2030 by 4%/year, creating a potential supply shortfall of 100 million metric tons/year (mmty), equivalent to about 12.8 Bcf/d of gas, by the end of the decade. Qatar would likely account for a large portion of the new supply with a planned expansion at its North Field East facility, the analysts said.

The United States has six export facilities in operation, with recent combined gas intake of more than 11 Bcf/d. The projects now under construction – Golden Pass in Texas, the sixth Sabine Pass train in Louisiana and Venture Global Calcasieu Pass also in Louisiana – would add roughly 4 Bcf/d of capacity in the next few years. Combined that would put total U.S output at around 15 Bcf/d.

The proposed U.S. liquefaction capacity far exceeds what could be built. Seventeen projects with a combined volume of 28.9 Bcf/d have already received construction approval from FERC, a process that costs into the hundreds of millions.

Four other projects with a combined output of up to 5.5 Bcf/d are in the Federal Energy Regulatory Commission’s pre-filing stage to identify major environmental issues and stakeholders. In addition, two more projects with a combined volume of 3 Bcf/d have been proposed to FERC but have not yet applied, according to the Commission.

Of the 17 projects approved by FERC,  only eight with a combined volume of 17.3 Bcf/d have an FID is planned next year, far more than global demand may warrant.

Expansions at existing facilities are said to be more likely to get funding than greenfield projects. Three expansions proposed for the Cameron terminal in Louisiana, the Corpus Christi project in South Texas, and at the Freeport facility on the upper Texas coast, would have combined volume of about 4 Bcf/d. Those projects have not publicly provided 2021 FID dates, but if they are sanctioned, it could leave less room to FID greenfield projects next year.

Two North American projects could potentially be funded this year, the 2.4 mmty Energía Costa Azul (ECA) facility in northwest Mexico and the 11 mmty stage 3 expansion at Corpus Christi. San Diego-based Sempra Energy last month sanctioned ECA, making it the only export project globally to reach FID this year.

Cheniere Energy Inc. said last month it would focus its immediate efforts on marketing an additional 7 mmty from debottlenecking the existing Sabine Pass and Corpus Christi facilities before sanctioning the third stage at Corpus Christi.

Among the greenfield projects vying to reach FID next year, two of them sustained significant setbacks in signing long-term customer deals. India’s Petronet LNG Ltd. backed out of a preliminary deal to invest $2.5 billion in Tellurian Inc.’s proposed 27 mmty Driftwood facility in Louisiana. France’s Engie SA ended negotiations for a 20-year, $7 billion supply deal with NextDecade Corp.’s 27 mmty Rio Grande LNG project in Texas. Both of the developers said they expect to sign enough deals to fund their respective projects next year with smaller initial capacities.

Even though the existing U.S. projects are exporting at record rates, their long-term customers could still be losing money because the arbitrage opportunities are not always high enough to offset sunk liquefaction fees of $2.25-3.50/MMBtu.

Most proposed projects are now likely offering take-or-pay liquefaction fees in the low $2/MMBtu range, Delfin CEO Dudley Poston told NGI earlier this year. The 13 mmty Delfin project offshore Louisiana, which would use abandoned pipelines in the Gulf of Mexico to bring in feed gas, is targeting an FID next year.

However, lower liquefaction fees may not be enough to entice customers. Tellurian has offered a unique model to sell long-term offtake rights, with 1 mmty for every $500 million of investment. It wants to own upstream and pipeline assets with the goal of providing low free-on-board prices of $3.50/MMBtu.