Is The Drag From LNG About To Switch To Help Gas Market?
“Cheap surplus natural gas created the U.S. LNG business. A gas surplus ruined it by driving global gas prices down to match U.S. prices. Global gas prices are rising, likely relieving pressure on the U.S. gas market. ”
The year started well for the LNG business, as shipments were strong and gas output continued growing due to more associated gas from crude oil wells, even though the oil well count was falling. The market forces continued to depress gas prices, ensuring that the spread between wellhead prices – the cost for LNG buyers – and export prices remained profitable. Then came Covid-19 and the global economic shutdowns that sapped demand for energy, and in particular LNG. The demand for LNG was further hurt by the consecutive warm winters in Europe that swelled gas storage, reducing the need for imported supplies.
The changed global LNG market became evident in May when customers began cancelling future cargoes. The pace of cancellations escalated as we moved into the summer months. According to various sources, there were two cargoes cancelled in April, but the number ramped up sharply in June and July when 44 and 45 cargoes, respectively, were cancelled. Forty cargoes were cancelled in August, but the market looks to be improving in September with estimates of only between 15 and 26 cargoes being cancelled. Buyers are required to notify LNG producers by the 20th of the month that is two months ahead of the shipping date.
The challenge for the global gas market has been weakening demand in Asia and Europe that saw prices fall to levels close to Henry Hub prices, which destroyed the economics of shipping gas. Although a substantial volume of LNG capacity in the U.S. is tied to long-term contracts, consumers were often faced with losses on shipments and potentially no place to put the gas once it arrived. This reality was reflected in prices. In 2018, prospects for a booming LNG business in the United States were strong, as the spread between Henry Hub and Asian gas prices were $7-$9 per thousand cubic feet (Mcf).
Prices in Asia began sliding following the winter of 2018-2019, to levels that provided only a few dollars per Mcf as we headed toward the winter of 2019-2020. After the spread widened by a few dollars, prices again began to slide. The price decline appears to have bottomed recently at levels comparable to Henry Hub. Even when Henry Hub spot natural gas prices are below global spot prices, the additional costs associated with U.S. LNG exports reduces their economic viability. Gas export terminals charge anywhere from $2 to $3 per million British thermal units (MMBtu) to liquefy the gas. Tanker transportation costs to Asia from the Gulf Coast terminals range from $0.60 per MMBtu to Japan to $0.81 to China. The reported rule of thumb is that Henry Hub spot prices should be roughly $2.00/MMBtu lower than other global spot gas prices for shippers to earn a profit.
Exhibit 11. Convergence Of Global Gas Prices Hurt LNG SOURCE: RBN Energy
A reason why European gas prices are depressed is the state of the gas market on the continent. Recently opened pipelines are bringing more supply to market, and that capacity may grow further. However, the greatest problem is the storage situation.
Exhibit 12. High Europe Gas Storage Limits LNG Sales SOURCE: GIE, PPHB
To appreciate how the gas storage situation in Europe has become a barrier to U.S. LNG shipments, we point readers to the chart in Exhibit 12 (prior page). It shows the volume of gas in storage in Europe (measured in energy terms), according to data from the Gas Infrastructure Europe web site, for 2011 through to July 20, 2020. We have marked the peak storage, which occurred during the winter of 2019. The more telling message is the dotted line showing how the gas storage volume, as of July 20, 2020, compares to the peak volumes recorded in 2018 and 2017, and that it is not far away from the 2016 peak. It is likely gas storage volumes heading into the coming winter season will reach a level comparable to that experienced in 2019. Given this situation, one needs to ask: Why does Europe need more gas, especially LNG shipments?
What is encouraging LNG sellers is futures spreads showing that they are widening as we head into the fall. A chart from Timera Energy shows various gas futures prices. The chart tracks the futures prices for Henry Hub (HH) gas prices, as well those for Europe (TTF), the United Kingdom (NBP) and Asia (JKM). It shows that all gas prices are currently in the $1.50-$1.80 per MMBtu range. However, by late winter 2020-2021, gas futures prices in Europe, the U.K. and Asia range between $4-$5/MMBtu, a substantial improvement. For U.S. LNG shippers, if Henry Hub gas prices remain below $3/MMBtu, there is a positive spread, which should cover a large portion of the associated costs of shipping LNG.
Exhibit 13. International Gas Futures Offer US Hope SOURCE: Timera Energy
The impact of the convergence of global natural gas prices has been the cancellation of approximately 150 LNG cargoes and a resulting decline in the feedgas flow to export terminals. In April, that flow was about 8.0 billion cubic feet per day (Bcf/d), which fell to 6.4 in May and only 3.9 Bcf/d in June. Reports are that feedgas flows have remained relatively stable in July. It is possible LNG exports may fall further in July, especially if the anecdotal information about cargo cancellations proved accurate. That reported data is that for the week ending July 15, only four LNG carriers with 15 billion cubic feet (Bcf) of gas departed the Gulf Coast, the lowest weekly volume shipped since the end of 2016. If the number of LNG cargo cancellations in September is as low as suggested, then feedgas flows to export terminals should be recovering. That would be welcome news for the industry.
Exhibit 14. LNG Sales Slump Hurt U. S. Gas Market SOURCE: Timera Energy
A big question for U.S. LNG shippers is what happens if significantly higher natural gas prices materialize in 2021. There are numerous forecasts suggesting that rather than natural gas prices remaining below $3/MMBtu next year, the decline in associated natural gas output due to falling oil well drilling will send futures prices closer to $4/MMBtu, or possibly higher. Without higher prices in Asia and Europe than currently projected by the futures strip, U.S. LNG profitability will be squeezed. This possible scenario has likely contributed to the delays in final investment decisions for new LNG liquefaction capacity.
A forecast from GlobalData.com (next page), shows that Asia will be the most vibrant LNG market in the foreseeable future, when measured by planned increases in regional gasification capacity. The forecast, based on planned and announced capacity expansions, shows the global LNG market increasing 30% between 2020 and 2024. That growth will be led by Asia, up 42%, followed by the Middle East growing 35%.
The Asian market growth, consisting of 39 planned and 14 announced terminals, will be driven by China. China’s Tangshan II is the largest new LNG regasification terminal with a capacity of 584 Bcf by 2024, followed by Son My II with a capacity of 450 Bcf.
Although the Middle East will grow faster than Europe, it will still rank third in 2024. The Middle East in 2024 will represent 9% of the
Exhibit 15. Asia continues To Dominate LNG Market SOURCE: GlobalData.com, PPHB
global LNG market compared to 10% for Europe. The Middle East has two planned projects, with a combined capacity of 1,447 Bcf. Kuwait’s Al-Zour terminal will be the largest of the two with a capacity of 1,155 Bcf by 2024. Bahrain Floating is expected to have a total capacity of 292 Bcf by the end of forecast period.
The European market will have only a 21% increase in regasification capacity. That expansion will be led by Germany’s Wilhelmshaven Floating and Brunsbuttel terminals. These will be two of the largest terminals in the region with capacities of 353 Bcf and 282 Bcf, respectively, by 2024. The region’s third largest terminal is Spain’s El Musel, with a total capacity of 247 Bcf. It is interesting that North America will show no regasification capacity expansion, showing just how much producers are convinced that the region will be self-sufficient in gas with surplus capacity available for export.
The next two years will be very interesting for the U.S. natural gas industry and LNG. If prices remain depressed, as they have been for the past year, the U.S. LNG business should prosper, as Asia, and possibly Europe, experience higher prices. On the other hand, should U.S. natural gas prices climb into the $3.00-$3.50/Bcf range, without even higher global prices, U.S. LNG shippers will find their profitability under pressure. One can build a case for each scenario. Knowing which scenario will occur is impossible to know now. From 2003 to 2009, U.S. gas prices were in the $6-$8/MMBtu range, a level that snuffed out interest in exporting gas. We needed it.
As gas supply began growing as a result of the fracking boom, suddenly prices fell to $4 and then $3/MMBtu. When the surge in associated natural gas from the shale oil drilling boom arrived, gas prices sank to $2/MMBtu. It was that supply surge that kicked off the LNG export boom, which has recently completed its first phase, and is soon expected to begin its second phase, assuming people are confident in sustained gas production well domestic gas consumption and increased exports to our North American neighbors. The Energy Information Administration (EIA) forecasts that U.S. natural gas production in 2020 will average 89.2/Bcf/d, compared to 92.2/Bcf/d output in 2019. The 3% decline between 2019 and 2020 will double to -6%, as the EIA projects production falling to 84.2/Bcf/d in 2021. They anticipate the production decline will start to reverse during the second half of 2021, in response to higher gas prices. The EIA forecasts gas prices will average $1.93 per thousand cubic feet (Mcf) this year, but jump to $3.10 in 2021. What will that do to U.S. LNG competitiveness?
The Age of Natural Gas is well underway. The recent move by Chevron to purchase Noble Energy is a statement that its executives believe natural gas will become even more important in the future than it is now. At year-end 2018, 62% of Noble’s reserves were natural gas, located primarily in Israel and Equatorial Guinea. As a cleaner burning fossil fuel, and one that can replace dirtier fossil fuels, natural gas demand should continue growing. The deal will add to Chevron’s natural gas portfolio.
We suggest people watch the U.S. natural gas market closely. What happens to supply, given low oil prices that restricts associated natural gas, will drive gas prices substantially higher. That potentially could make U.S. LNG less competitive globally. We wonder whether the U.S. LNG market is reaching its realistic capacity, at least for the foreseeable future, until the global gas surplus is absorbed by increased demand. Until that happens, it is difficult to see LNG being the main driver of the U.S. natural gas market.