The global LNG market upheaval has wreaked havoc on U.S. LNG export demand this summer, which, in turn, has complicated operations at domestic export facilities. Gone are the days when U.S. LNG exports would move predictably, increasing with each new liquefaction train coming online and then mostly staying at or near capacity. Rather, as international LNG prices collapsed, U.S. LNG operators for the first time have had to contend with a relentless stream of cancelled cargoes and low facility utilization rates. More recently, cargo cancellations are showing signs of easing somewhat, as international price spreads are improving for fall and winter. But these recent market disruptions provide a window into the ways in which operational constraints and flexibilities will factor into LNG producers’ and offtakers’ decisions — and affect feedgas flows and capacity utilization — in a weak global market. Today, we consider some of the nuances of liquefaction operations.
U.S. LNG producers, like much of the rest of the energy sector, were dealt a difficult hand in 2020. Even before the COVID-19 pandemic, the global LNG market was already drifting toward oversupply conditions and a slowdown in global LNG demand growth. International gas price spreads had been converging as new export projects in the U.S. and Australia were completed and started flooding the market with LNG. The global LNG market was gradually heading for a reckoning of sorts. However, the pandemic — and resulting lockdowns and demand destruction — triggered a collapse, and even reversal, in price spreads that put U.S. LNG largely out of the money and culminated in what was previously considered improbable: cancellations of U.S. cargoes and low utilization of U.S. liquefaction capacity.
As the fallout from COVID-19 has stretched into summer, cancellations of U.S. cargoes have become a regular occurrence in the U.S. gas market, though they are starting to ease now as the global supply-demand balance has tightened and price spreads have widened somewhat. U.S. LNG export demand contracted by more than 60% since early 2020, with most of the facilities operating at much lower utilization rates (Figure 1). The exceptions were Cove Point LNG, which has kept producing at normal rates, and Cameron LNG, which commissioned two of its trains during this period. (We discussed these trends and the economics behind the cancellations in Break It to Me Gently Part 1 and Part 2, and more recently in Undone).
Figure 1. U.S. LNG Export Demand vs. Liquefaction Capacity. Source: RBN
The days of steady rates of U.S. LNG production paced solely by capacity additions and maintenance are clearly over. In recent months, they’ve been replaced by a steady stream of cancellations. But this pattern will wear off as winter demand picks up in Europe and elsewhere and storage constraints ease. What is likely to persist, though — at least as long as global prices remain low and margins thin — will be a market where U.S. LNG export demand, and the resulting domestic feedgas requirements, are susceptible to the economic twists and turns of the market, influenced both by domestic factors as well as changes to fundamentals abroad.
That shift raises the questions: how flexible can U.S. liquefaction facilities be, and what options do U.S. LNG producers have for optimizing their plants during challenging times? Next, we discuss the operational tools and constraints LNG producers have for responding to short-term market events. We should preface our discussion by saying that we’re not engineers, and that this is not meant to be an exhaustive discussion of operational factors. Instead, our aim is to provide a window into some of the mechanisms that operators are turning to in order to weather the current market environment.
First, let’s get the limitations out of the way. As we explained in Steppin’ Out with My LNG, liquefaction facilities are an amalgam of multiple expensive and complex systems, including units for pre-treating, pre-cooling, and liquefying natural gas. These also require a number of ancillary systems, such as for powering the primary systems, monitoring and safety, and dealing with things like heavy hydrocarbon distillation, boil-off gas, storage, and cargo loading. Suffice it to say, a liquefaction train is not a system that can respond in real time to daily or even weekly market volatility. It takes facilities time to ramp trains up and down; it’s not a process that can be turned on and off daily; and, in fact, it takes planning and coordination between the offtaker and LNG producer weeks and even months ahead of when cargoes are scheduled to be lifted.
The planning process is laid out in each customer’s long-term contract. It starts with an annual delivery program (ADP), which is negotiated between the LNG producer/operator and offtakers before the start of each new contract year, typically between August and November. That plan lays out the dates or windows that the specified volumes of LNG will be delivered for loading. Operators also typically provide a 90-day schedule, usually sometime in the middle of each month, that specifies the timing of deliveries for meeting cargo requirements over the next three months. Offtakers can request to shift their lifting dates, but it’s up to the facility operator to grant the requests depending on, among other things, the availability of LNG supply at the requested date and a berth being available then for docking and loading the cargo. As we noted in Part 2 of Break It to Me Gently a few weeks ago, long-term contracts for U.S. LNG generally also provide a good amount of flexibility for canceling cargoes, but it requires advance notice to the operator — nearly two months in the case of Cheniere, which takes the responsibility of securing the feedgas for its offtakers.
Beyond the time constraints of the start-up and shutdown processes and the scheduling cycle, though, liquefaction trains technically have a considerable amount of operational flexibility; they can — and do — run at partial capacity. But doing that can lower efficiency and increase cost per MMBtu produced, which is why LNG producers are always looking to optimize their capacity. Additionally, onsite fractionation units for removing the heavy hydrocarbons from the gas stream also may have minimum flow requirements that affect turndown decisions for a liquefaction train. As a general rule, whatever technology is used, a train is most efficient when running consistently at a high utilization rate. But depending on the technology used, we’ve heard that trains can ramp down to somewhere in the 50-70% range of capacity without increasing cost or losing much or any efficiency. Much lower than that and you start to lose efficiency and have to shut down and restart, which takes time. For its part, Cheniere, which operates nearly 40% of total U.S. liquefaction capacity combined between its Sabine Pass and Corpus Christi facilities, has said it can operate its trains at 50% without losing much efficiency.
Whatever the technical parameters, though, the point is that while there is operational flexibility, there are potential costs and efficiency declines associated with ramping up and down or running at partial capacity. So, ultimately, the decision-making around that is often more of a commercial one than a technical one, and it is dependent on much more than commodity prices. Rather, it also comes down to who is going to be absorbing the operational and maintenance (O&M) costs and whether it’s a pass-through cost or one that is worth incurring when compared with the market opportunities. These factors, in turn, vary by facility or even by individual contracts at each facility, depending on the cost structure underpinning the offtake agreements, the particular terms of each contract, the types of offtakers, and the offtakers’ risks and commitments on the delivery end, among other things.
In Cheniere’s free-on-board model, for example, Cheniere passes the fixed O&M costs to its offtakers by charging a fixed take-or-pay fee, meaning they collect it regardless of whether offtakers lift a cargo or not. (It also charges a variable commodity fee equal to 115% of Henry Hub if the cargo is lifted.) But if costs increase beyond that fixed rate — due to efficiency declines, for example — Cheniere would be the one to absorb that. The good news for Cheniere is that it also has the commercial optionality to potentially offset those costs by marketing its own cargoes — or utilizing the same liquefaction capacity to re-market a cancelled cargo — through its marketing arm, Cheniere Marketing Inc. (CMI), if the spot market presents opportunities. Thus, when it comes to running a train at a lower rate, Cheniere would weigh those incremental costs against its ability to sell a cargo for an attractive price. In contrast, the other U.S. facilities are built on tolling models in which offtakers are effectively the LNG producers and more than likely responsible for covering O&M costs. So, at those facilities, it’s the offtakers who are typically weighing the commercial implications of O&M costs in the context of their portfolio and downstream opportunities.
The current environment — with increased global competition, tighter margins, and economic uncertainty — has greatly complicated these types of decisions. That said, U.S. LNG producers and offtakers have a number of levers they can use to optimize their liquefaction capacity.
One way to keep utilization up is to produce the LNG anyway and sell it in the spot market. In Cheniere’s case, the operator retains the rights to the liquefaction capacity if a cargo is canceled, which means that if the spot market provides enough of an economic opportunity, it can re-market the volume through its marketing arm. And, if there is money to be made by doing that, they will do that. The same goes for the offtakers at the other facilities. If a partial train is needed, the operator would likely opt to pace the LNG production over a longer period of time in order to deliver the volumes at the time they are needed, using onsite LNG storage tanks to fill any gaps.
If LNG producers do have to shut down whole trains, they would opt for the most efficient way, which would be to run the minimum number of trains at higher utilization rates in order to produce the volumes required by customers who have not canceled cargoes. Just about every U.S. facility now operates multiple trains (except for Cove Point LNG), and long-term customers generally hold contracts for capacity on specific trains. However, our understanding is that U.S. facilities also have in place inter-company agreements between the different joint-venture or operating companies that make up the producing ventures at each facility. So, for example, at a facility with three trains in service and two customers for each train, if one customer each cancels on two of the trains, the inter-company agreement allows the operator to shut down one train and consolidate the remaining four customers among two trains, regardless of which specific trains those four offtakers have contracted capacity on. In other words, it allows the LNG producer the operational flexibility to produce the required volume from the minimum number of trains and shut down the other trains as needed.
Another lever that U.S. operators have for avoiding running trains at lower, less efficient rates is bringing third party-sourced LNG supply into the mix. This involves securing supply from other LNG producers to help meet your customers’ demand without having to produce it yourself. Of course, an operator would only do this if it can source supply at a lower cost than it could produce it. Additionally, it would need to have the marketing and trading relationships in place to do that. Cheniere has the ability to do this via its marketing arm, and the operator in its earnings call on August 6 confirmed that in the second quarter of 2020, Cheniere was able to exercise its own commercial flexibility to take advantage of opportunities for buying cheaper LNG from other facilities that didn’t have that same flexibility or ability to respond as quickly to market events. Specifically, Cheniere said it increased its third-party LNG volumes in the second quarter of 2020 to 34 trillion British thermal units (TBtu), up from 14 TBtu in the first quarter. As for the other facilities, though, again, it would be the offtakers, not the operators, who likely would make that call on whether to lift a cargo or cancel and take their chances in the spot market, based on their portfolios and any obligations they have with their long-term buyers.
And, finally, it’s worth noting that there are ways facilities can optimize production per train through maintenance and mechanical tweaks, and producers will look to do that as they juggle demand swings. Cheniere, for one, said on its call a week or so ago that it has taken advantage of the recent downtime to push up some of its planned maintenance, and it expects to announce improved run-rate production guidance in its third-quarter 2020 results. (It had last announced an increased run-rate production guidance in June 2019, attributing it to production and maintenance optimization and debottlenecking projects at its Sabine Pass and Corpus Christi facilities.)
There’s no doubt that the market turmoil that has played out this spring and summer has forced U.S. LNG producers — and offtakers, for that matter — to get creative and employ all the tools at their disposal in order to optimize their operations and squeeze out revenue/margins where they can. That reality also injects many more variables into the U.S. LNG export demand outlook moving forward.
"Love Interruption" was written by Jack White and appears as the fourth song on White's debut solo album, Blunderbuss. Recorded at White's Third Man Studio in Nashville, the song was done live in one take to an eight-track analog tape machine, with the clarinet parts added in overdubs. The White-produced single was released in January 2012 and went to #13 on the Billboard Alternative Airplay chart and #27 on the Billboard Hot Rock & Alternative Songs Singles chart. Personnel on the recording were: Jack White (vocals, acoustic guitar, electric guitar), Brooke Waggoner (piano), Mindy Watts (background vocals), Fats Kaplin (fiddle), Bryn Davies (bass), Olivia Jean (drums), and Ryan Koenig (background vocals).
Blunderbuss was mostly written by White, and it was recorded and produced at his Third Man Studio in Nashville during 2011. The use of eight-track analog tape helped contribute to the organic, rootsy feel of the album. Released in April 2012, Blunderbuss went to #1 on the Billboard Top 200 Albums chart and has been certified Gold by the Recording Industry Association of America.
Jack White (John Anthony Gillis) is an American singer, songwriter, multi-instrumentalist, and record producer. In addition to being a solo artist, White was a founding member of The White Stripes and is a member of The Raconteurs and The Dead Weather. He has released three solo albums, three Raconteurs albums, three Dead Weather albums, and six albums with the now-disbanded White Stripes. He has won one Brit Award, 13 Grammy Awards, and five MTV Video Music Awards. White received an honorary doctor of humane letters degree from Wayne State University in Detroit. Originally from Detroit, White now resides in Nashville and Tulsa. He continues to record and tour.
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