It has been a chaotic couple of years for North American LNG and the global gas market. In a short time, international gas markets went from oppressively oversupplied balances, high storage inventories, and historically low prices for much of 2020 to reckoning with panic-inducing supply shortages, low inventories, and multi-year or all-time high prices in the biggest LNG-consuming regions. The resulting whiplash has transformed key aspects of the LNG market, making a profound impact on the way existing LNG terminals operate, how projects secure funding and capacity commitments, and what offtakers expect for the next generation of LNG capacity buildout. The tight market appears to have settled the question of whether more export capacity is needed, at least for now, but the market’s sharp U-turn has also put potential offtakers on edge and underscored the need for contractual flexibility. Additionally, pressure to reduce greenhouse gas (GHG) emissions is higher than ever, and LNG offtakers are increasingly demanding greener solutions to address government regulations and public concerns. This convergence of factors has put the LNG market at a crossroads. Taking all of the lessons learned from the last two years and before, the industry must now forge a new path forward. In the encore edition of today’s RBN blog, we discuss highlights from our recent Drill Down report, looking at the major trends that will define the North American LNG market in the coming years.
In observance of today’s holiday, we’ve given our writers a break and are revisiting a recently published blog on our Drill Down Report on North American LNG Markets. If you didn’t read it then, this is your opportunity to see what you missed! Happy Thanksgiving!
The domestic and international LNG markets today are almost unrecognizable from a year ago. At this time last year (yellow-shaded area in Figure 1), U.S. Gulf Coast LNG producers were still emerging from the peak of the cargo cancellations that occurred in the summertime, precipitated by COVID-related shutdowns and demand destruction around the globe. International gas prices had partially recovered from the all-time lows seen over the summer but were still near multi-year lows, while Henry Hub was languishing in the low to mid-$2/MMBtu range. The economics for delivering to Europe and Asia still left U.S. LNG mostly out of the money (see Sultans of Swing for a detailed breakdown of export economics). For example, the Japan-Korea Marker (JKM; gray line on the right axis), the oldest and most liquid LNG price index and a good representation of the global LNG market, fell to historic lows near $2/MMBtu in the spring of 2020 and carried $2 handles through much of that summer. As COVID conditions in Asia began to ease (earlier in Asia than in Europe or the U.S.) last year, JKM prices staged a modest recovery but stayed below $3/MMBtu until the September contract expired in mid-August and prices began climbing from there. This time last year, prices were on the rise, heading for $10/MMBtu.
As for domestic feedgas deliveries to the terminals (blue line on the left axis), they had gone from flowing at rates of nearly 100% utilization of operating liquefaction capacity pre-COVID, down to more like a third of the estimated total feedgas requirement (orange line on the left axis) in July 2020. By September 2020, as cargo cancellations were starting to ease, feedgas flows had begun to recover but were still running at little more than 50% of the total requirement. Overall, there was still a great deal of uncertainty about when, how, and by how much global gas demand would recover. With much of the existing capacity sitting idle, the idea of building or expanding LNG terminals, which was already losing favor before COVID, became downright unpalatable. Export projects were losing offtaker or developer interest and being canceled or paused (see Holding On for Life).
Figure 1. Monthly U.S. LNG Feedgas and Capacity vs. JKM Prices. Source: RBN LNG Voyager
Fast forward to a year later, and the market is facing just the opposite: an extreme undersupply situation that has driven prices to the longest and strongest bull run in the Shale Era, if not ever. JKM has catapulted to all-time highs this fall and is averaging above $30/MMBtu in November to date (gray line in the shaded green area), more than $10/MMBtu above the all-time high prior to this fall seen in January 2021, when constraints for transiting the Panama Canal were causing severe delays and vessel shortages, resulting in prices spiking to near $20/MMBtu. At the same time, European gas price indices (not shown in the graph) have shown continued strength and volatility. You can read more about the reasons why — low storage inventories, low imports, steep competition for cargoes, and robust demand, among them — in Too The Moon and Back. But suffice it to say, U.S. feedgas demand has more than recovered this year.
After Corpus Christi Train 3 came online in late March, total feedgas reached a record of 11.24 Bcf/d and averaged an astounding 10.77 Bcf/d this past April (see Such Great Heights). Feedgas flows subsequently retreated from those record levels in the spring and summer, primarily due to pipeline maintenance and related constraints in moving gas to the terminals, particularly in Louisiana. That record from late March still stands. Nevertheless, deliveries to the terminals averaged just shy of 10 Bcf/d from May through August, up an average 5.5 Bcf/d from the same period last year. Moreover, feedgas demand is headed even higher soon. Sabine Pass Train 6 and Calcasieu Pass are both currently commissioning and due online in the near future. Sabine Pass Train 6 is reported to be on schedule and has been taking significant feedgas, as much as 300 MMcf/d on some days. Cheniere announced Monday that the train had started producing first LNG. Calcasieu Pass is heard to be taking small amounts of feedgas, about 15 MMcf/d, mostly to run power generators. It is reported to be running a bit behind schedule, so first LNG would likely not occur until 2022. The addition of these projects will add more than 2.25 Bcf/d of new feedgas demand to the U.S. Gulf Coast, all but ensuring that we’ve not yet seen the highest feedgas levels this year.
Beyond 2022, a handful of projects that reached a final investment decision (FID) prior to COVID are still under construction, including Golden Pass along the U.S. Gulf Coast and two new terminals outside the U.S. — Energía Costa Azul (ECA) LNG in Mexico and LNG Canada in Canada. The latter two will export from the Pacific Coast, which is becoming a hotbed of LNG development because it bypasses the Panama Canal constraints and provides a more than $1/MMBtu transport cost advantage over the Gulf Coast thanks to its proximity to the all-important Asian markets. Of course, the ease of sourcing gas in the Gulf Coast counterbalances some of that advantage, and at this point, more LNG development in both areas seems likely, albeit with a different scope and pace than was expected in the previous decade (the 2010s) when North America was first entering the global gas market.
Any new LNG development is a welcome change from where the market was in summer 2020, when we were witnessing a slow-motion meltdown among the second wave of North American LNG export projects that saw many of them delayed, put on the back burner or canceled. The rapid swing to undersupply and prolonged high global gas prices have renewed interest in offtake agreements and new LNG buildout. Support is coalescing around a handful of North American LNG projects that may take FID in the next year or so (see Only the Strong Survive and You Can Make It If You Try). However, offtakers and developers have learned a number of lessons from recent events, and the contracts underpinning these projects look very different from those that supported the first wave of North American LNG. For one thing, new deals signed in recent months share the market risks and rewards between LNG buyers and sellers, and offer LNG indexed to a variety of different global price indices, as opposed to just Henry Hub, as was the standard for the first-wave projects. The latest deals often also offer shorter terms in order to appeal to offtakers who are working to balance the need for reliability with long-term uncertainty, particularly as environmental regulations tighten worldwide.
Another consideration that wasn’t on the radar during the first wave of projects but is now practically a requirement: going green. As the pressure to become greener has intensified, LNG producers and developers are looking at ways to reduce or offset emissions. This effort is not only an essential strategy for the next generation of LNG terminals but one that is being explored by existing terminals as well. LNG offtakers are increasingly looking for “green” LNG cargoes and contracts and to minimize or offset their carbon footprint. Carbon-neutral LNG cargoes have already been produced and sold from U.S. terminals, using carbon credits (see A Matter of Trust). A number of existing and planned LNG terminals are exploring carbon sequestration options. And, finally, many of the new terminals that go forward are likely to opt for an all-electric liquefaction process to reduce emissions.
Overall, the North American LNG industry has demonstrated a resilience over the past two years that has cemented its position as an important marginal producer for global markets. LNG developers have had to shift strategies to attract offtakers, focusing on green initiatives, shorter contracts, and diverse pricing structures and that, coupled with growing global demand, has ensured that North America has not seen its last LNG project take FID. With gas demand growth led by Asia, as well as increasing Russian exports to Europe decreasing that market’s reliance on LNG, the next wave of North American LNG development is exploring new Asia-centric strategies — specifically with new projects announced in Mexico and Canada on the Pacific Coast. Some of these projects could move quickly and bypass a number of previously announced Gulf Coast projects on their way to FID. But don’t count the Gulf Coast projects out either, as the market weighs the relative ease of supply access along the Gulf Coast versus easy access to the increasingly important Asian markets from the Pacific Coast. All in all, 2022 could realistically see multiple projects from both the Gulf and West coasts take FID.
In this Drill Down report, we take a look at North American LNG and its place in the global gas market, which is at a crossroads as near-term supply shortages intersect with long-term demand uncertainty. We examine how we got here, what it means for LNG now and most importantly, what the future of North American LNG looks like. For more information on the Drill Down report, click here. The latest news in the LNG market is also available in our latest RBN LNG Voyager Quarterly Report, available here.
"Crossroads" was first written and recorded as "Cross Road Blues" by Robert Johnson in 1936, with his recording released the following year. This song has a lot of mythology surrounding it, with the main story being that Johnson was a guitarist with limited skills until he sold his soul to the devil at the crossroads described in his song. There is a roadside landmark at the intersection of Highway 61 and Highway 49 in Clarksdale, MS, where this event is said to have transpired. American blues artist Elmore James also released two versions of the song, one in 1954, and the other in 1965. Cream recorded its version of the song — retitled "Crossroads" and including a verse from Robert Johnson's "Traveling Riverside Blues" — in November 1966 for broadcast on the BBC Guitar Club radio show. The band recorded a longer live version of the song at the Winterland Ballroom in San Francisco in March 1968. It is this version that leads Side 3 of Cream's two-disc 1968 album, Wheels of Fire. Personnel on the record were: Eric Clapton (vocals, guitar), Jack Bruce (bass), and Ginger Baker (drums).
Wheels of Fire is the third album released by Cream. Disc 1 of the double-LP was recorded in the studio at IBC Studios in London, and Atlantic Studios in New York City. Disc 2 features live material recorded by the band at the Winterland and Fillmore ballrooms in San Francisco. Produced by Felix Pappalardi, the record was released in the U.S. in July 1968 and went to #1 on the Billboard Top 200 Albums chart. It has been certified Platinum by the Recording Industry Association of America. Two singles were released from the album.
Cream was a British rock power trio formed in London in July 1966 with Eric Clapton, Jack Bruce, and Ginger Baker. They released four studio albums, four live albums, 10 compilation albums, and 10 singles. They are members of the Rock and Roll Hall of Fame and have a Grammy Lifetime Achievement Award. The band announced its breakup in May 1968 and performed its final live show in November of that year. Cream reunited to perform three songs live during its induction into the Rock and Roll Hall of Fame in 1993. The band reunited again for four shows at the Royal Albert Hall in London in May 2005 and three shows at Madison Square Garden in New York City in October 2005. All three members of Cream went on to successful careers as solo artists and members of other ensembles. Jack Bruce died in October 2014, and Ginger Baker in October 2019. Eric Clapton continues to record and perform live.