economics

It’s been an incredibly wild year for U.S. LNG exports. In the past year, global gas prices have seen both historic lows and highs, as markets swung from extreme demand destruction from COVID-19 for much of last year, to supply shortages by late 2020 and into early 2021 due to maintenance outages, weather events, Panama Canal delays, and vessel shortages. The U.S. natural gas market has also dealt with its share of anomalies, from a historic hurricane season in 2020 to the extreme cold weather event last month that briefly triggered a severe gas shortage in the U.S. Midcontinent and Texas and left millions of people without power for more than a week. Given these events, U.S. LNG feedgas demand and export trends have run the gamut, from experiencing massive cargo cancellations and low utilization rates to recording new highs. Throughout this incredibly tumultuous year, U.S. LNG operators have had to adjust, managing the good times and bad and proving operational flexibility in ways that will serve them for years to come. Here at RBN we track and report on all things LNG in our LNG Voyager report, and we’ve been hard at work enhancing and expanding our coverage to capture the rapidly evolving global and domestic factors affecting the U.S. LNG export market, including terminal operations, marginal costs and export economics, and international supply-demand fundamentals. Today, we highlight how U.S. LNG has changed in the past year and trends to watch this spring. Warning! Today’s blog is a blatant advertorial for our revamped LNG Voyager Report.

On the 8th of October, the LNG carrier Golar Penguin loaded a cargo for RWE at the Freeport LNG terminal in Texas. Five days later, on October 13, the vessel was sitting just north of Panama. But then, the ship abruptly changed direction on the 14th and headed towards the Cape of Good Hope to deliver to the Far East. The reason for the diversion was that the vessel did not have a passage booked in the new locks of the Panama Canal and would have had to wait approximately nine days for its turn to transit, before heading across the Pacific Ocean to Asia. Since then, as queues of LNGCs for Panama Canal transits, both northbound (ballast) and southbound (laden) have developed, more ships have opted for the longer route. In today’s blog, we look at the delays that have developed surrounding the Panama Canal and the implications that its operations hold for global LNG trade.

Global LNG demand has picked up, cancellations for U.S. cargoes have subsided, at least for now, and there’s upside to U.S. cargo activity once tropical storm-related disruptions are resolved. But positive netbacks year-round are no longer a foregone conclusion for U.S. offtakers. As global oversupply conditions persist, at least on a seasonal basis, and supply competition intensifies, the economic decision to lift U.S. cargoes will be much more nuanced than it was in previous years. What do the economics for cargoes this winter and beyond look like? Today, we put the LNG economics model to work to understand what’s in store for U.S. LNG in the coming months.

The economics for U.S. LNG entered new territory this year, as price spreads to international destinations, particularly from the Gulf Coast export terminals, went from an average $4-8/MMBtu a couple of years ago to $1/MMBtu or less in 2020 to date. The tighter spreads reduced netbacks for U.S. offtakers and led to mass cargo cancellations this summer. Moreover, current futures curves show Henry Hub price spreads to Europe and Asia staying mostly in the $1-$3/MMBtu range over the next few years, suggesting that the arbitrage for U.S. LNG exports, particularly from the Gulf Coast terminals, likely will remain tighter and make commercial decisions to lift or cancel U.S. cargoes much more nuanced than they ever were before. Today, we delve into the primary cost components that factor into offtakers’ netbacks.

Philadelphia Energy Solutions (PES) announced last week (on June 26) that it was shutting down its 335-Mb/d refinery in Philadelphia, PA. This announcement came just five days after a major fire destroyed a portion of the refinery, which turned out to be the last straw for the facility that has been struggling financially for many years. Today, we consider the various market impacts that will likely follow the closure of the PES refinery, including its effect on fuel supply, where the closure leaves refinery production capacity in the region and how the refined product supply will need to adjust in response.

Dominator. Showboat. Brass Monkey. These are not player names in the re-established XFL; these are project names given to colossally proportioned drilling pads in the Permian and Appalachia. A single one of these well pads can be home to 20, 30, even 60 or more permitted well spots, each with miles-long laterals branching out in multiple directions. In today’s blog, we begin a series exploring the motivations that sparked this trend to larger pads and discuss the impact they’re having on the upstream and midstream sectors. 

The shale boom breathed new life into East Coast refineries that were under threat of closure by their owners between 2009 and 2012. Now some of those same refineries are under threat again, this time due to poor margins as well as the high cost of compliance with environmental regulations. After enjoying three years of improved margins through access to advantaged domestic crude delivered by rail from North Dakota, five East Coast refineries are now paying international prices for imported crude again in 2016 after differentials between domestic benchmark WTI and international equivalent Brent narrowed to less than $1/bbl in the wake of the crude price crash and an end to the federal ban on most crude exports. Today we discuss PADD 1 refinery prospects.

If East Coast refiners bought their crude at the wellhead in North Dakota during February 2016 they would have paid average prices of about $4.90/Bbl below U.S. Benchmark West Texas Intermediate (WTI) at Cushing, OK – which works out at about $26.25/Bbl (price estimates from Genscape). If they shipped that crude by rail to refineries in Philadelphia, PA on the East Coast they would have paid about $14/Bbl rail freight - meaning the delivered cost of crude would be $26.25 + $14 or $40.25/Bbl. Alternatively they could have simply imported Bakken equivalent light sweet crude priced close to international benchmark Brent for an average $34/Bbl – saving a minimum of $6.25/Bbl. Today we describe how these economics have had a detrimental impact on crude-by-rail (CBR) shipments to the East Coast.

Projected growth in U.S. methanol production was based in large part on the expectation that domestic natural gas prices would remain significantly lower (on a per-MMBtu basis) than the price of crude oil, and that Asian demand for U.S.-sourced methanol would continue rising at a fast clip. Today both of those assumptions look dicey.  Natural gas prices remain low, but crude prices have languished below $50/Bbl for most of the past two months, and there are worries that China (by far the world’s largest methanol consumer) may be an economic bubble about to burst. Today, we consider recent developments that could slow the long-anticipated growth in natural gas use by U.S. methanol producers.

Average margins for a Gulf Coast condensate splitter have been about $5/Bbl better in 2015 than they were in 2014 but are still about $4.75/Bbl worse than an equivalent Gulf Coast 3-2-1 crack spread. The economics of condensate splitters have also yet to be tested in an environment if – as could happen later this year – crude production begins to decline. Are condensate splitters a better investment than just exporting lightly processed condensate under relaxed export regulations? Two companies considering projects seem to have reached different conclusions recently. Today we continue our update on splitter projects with a look at economics.