Top 10 RBN Energy Prognostications for 2023, Encore Edition – Year of the Rabbit

Worried about 2023? Well, you’ve got good reason to be. This year energy markets are at the mercy of a hot war in Europe, the threat of a global recession, looming China/Taiwan hostilities, the impending onslaught of new energy transition programs from recent legislation, and all sorts of other random black swans paddling around out there. With so much uncertainty ahead, predictions this year would be just crazy talk, right? Nah. No mere market murkiness will dissuade RBN from sticking our collective necks out to peer into our crystal ball one more time. Let’s hope it’s no bad bunny.

But before we get started ... We’ve been at this prognostications business for 11 years now, and one of our long-standing traditions is not just to look forward, but also look back to see how we did the previous year. Yes, we check our work! Somewhat surprisingly (even for us), our accuracy rate was pretty good last year, particularly considering how wild and unpredictable 2022 turned out to be. You can see how we did in our Prognostications Scorecard, which was posted yesterday.

2023 — Year of the Rabbit

Years ago, when we first started prognosticating, we needed all the help we could get to see into the future. So we consulted the Chinese zodiac. It’s been a useful analytical tool. In 2015, after the Shale Era’s first oil price crash, we had Year of the Goat — oil was certainly the goat that year. In 2016, it was Year of the Monkey — a lot of monkey business going on. In 2018, it was Year of the Dog, and we asked, “Who let the dogs out?” We were getting greedy in 2019, Year of the Pig. And of course, 2020 was Year of the Rat, 2021 Year of the Ox, and 2022 Year of the Tiger. So how about 2023?

Yup. Year of the Rabbit. Hmm. What’s up with that? Well, the Chinese see rabbits as quick, quiet, trustworthy, and likely to avoid a fight. The zodiac sign is a symbol of luck and longevity. Energy markets could certainly use some luck right now, and avoiding fights sounds really good. But the zodiac also says those wascally wabbits can be zany, tricksome, even a bit emotionally unstable. We have to look no further than Bugs Bunny and Roger Rabbit to see what that could mean. How does that all add up for 2023 energy markets. Let’s find out.

We’ll start at #10 and work our way up to #1.

  1. VLCC economics will accelerate the shift to Corpus Christi crude export dominance. In 2022, a whopping 60% of U.S. crude oil exports moved out of Corpus Christi, double the volumes from Houston and dwarfing the volumes from Beaumont and Louisiana. The initial push for the dominance of Corpus exports came from new Permian pipeline capacity to various docks across the port that came on in 2019-20, redirecting volumes that were going to other export anchorages. But lately, increasing volumes out of Corpus have come almost exclusively from only two terminals: Enbridge (formerly Moda) and South Texas Gateway, the two deep-draft onshore dock facilities in Ingleside (just across the bay from Corpus). These docks are special because they can load a Very Large Crude Carrier (VLCC) almost full. We predict that volumetric shift to Corpus will accelerate in 2022. The reason is shipping economics. VLCCs enjoy huge economies of scale versus smaller ships, and that became a much bigger deal in 2022 as the Russia/Ukraine war redirected crude flows into much less efficient routings, which has had the effect of blowing out ship charter rates. And because Enbridge and STG have the advantage of avoiding most of the high cost of “reverse lightering” a VLCC due to their unique deep-draft facilities, these docks are sucking crude away from all other export facilities, even the Louisiana Offshore Oil Port (LOOP), which can fully load a VLCC but has logistical challenges of its own. We’ll explore more about the Corpus crude export phenomenon in other prognostications below.  
  1. The 2023 hiatus on new LNG export-capacity additions will trigger the last oversupplied gas market for a long time to come. In every year since 2016, when the first Lower 48 LNG export facility came online, U.S. export capacity and export volumes have increased. Flows were up even in the COVID meltdown year of 2020, and again in 2022, even with Freeport LNG out of service for most of the year. But things will be different in 2023. No new LNG export capacity is slated to come online for the year. Of course, Freeport will finally restart, but that’s return of existing capacity, not new liquefaction. What’s the issue with a pause on LNG export capacity increases? Well, natural gas production is growing. At RBN, we are looking at a Lower 48 year-on-year dry gas production increase of 5-7 Bcf/d, with December 2023 reaching 102.5 Bcf/d. Where will all that incremental gas go, assuming power generation is already taking a lot of supply and exports will max out? The answer is ... inventories. And as inventories build, that will most likely translate to lower prices versus 2022. But for you gas bulls out there, don’t get too down in the dumps. Starting in 2024, new LNG export capacity starts to ramp up, potentially turning into a torrent over the coming years. Can production growth keep up with all that LNG export capacity? Probably so. But it will be touch and go in some years, with little chance of gas market oversupply conditions coming back after 2023 for a very long time to come.
  1. NGL production will keep coming on strong in 2023, pushing more volumes to export markets. The past year was a great one for NGL production — up 8% over 2021, as compared to a more modest 4% crude oil increase, and only a 3% gain for natural gas. Why the outsized jump in NGLs? Well for one thing, some of the most prolific natural gas is coming from “wet” (high NGL content) basins, especially the Permian, yielding a disproportionate share of liquids-bearing gas. Second, most oil basins are getting gassier, both because older wells produce more gas and because — at today’s much higher natural gas prices — producers are more inclined to drill in gassy areas, especially if the associated gas comes with a high NGL content. And finally, midstreamers are doing their part — building a significant number of gas processing plants: at least a dozen over the next two years in the Permian alone. New processing capacity means more NGLs. All of those factors will continue in 2023, limited only by the infrastructure (gathering systems, pipelines, fractionation, etc.) needed to get those NGLs to market.
  1. Canadian crude flows into the U.S. will drop in 2023, narrowing the WTI-WCS differential. At some point in 2023, the long-awaited TransMountain Expansion Project will be coming online, increasing the pipe’s capacity from 300 Mb/d to 890 Mb/d to move mostly incremental heavy crude from Alberta to an export facility at Burnaby, British Columbia. Some of those barrels will be exported to the U.S. West Coast, while other volumes will move to Asia — most likely China. Where it won’t be moving is to legacy destinations — Midcontinent refineries via the Enbridge Mainline, Keystone and other pipes. When those barrels shift to the BC export market, two things will happen. First, the price spread between Canadian crudes such as Western Canadian Select (WCS) and West Texas Intermediate (WTI) will narrow as U.S. refiners bid up the price to hold on to some of the Canadian barrels. That will translate into higher crude prices for all refineries taking Canadian barrels. And second, Canadian crude flows to the U.S. will decline for a year or two until production volumes catch up with the new demand. Expect that flow shift to have significant implications for domestic crude differentials until the changes work their way through the market.
  1. Appalachia will see the last throes of natural gas production growth in 2023-24 as takeaway capacity maxes out. Marcellus/Utica production is getting close to hitting the capacity wall. After growing like crazy for years, production growth slowed dramatically in 2022, with output coming in essentially flat, not only due to constrained pipeline takeaway capacity but also because producers slowed drilling in part to avoid hitting the capacity wall — the Marcellus/Utica version of producer restraint. Pipeline maintenance, freeze-offs and other factors also contributed to the slowdown. Of course, going forward it looks like there will be no new pipeline capacity out of the region, assuming the Mountain Valley Pipeline is in permanent limbo. Production is already up to more than 34 Bcf/d and constraints limit production to no more than 35 Bcf/d during the shoulder months. So most likely takeaway constraints will hit during the fall of 2023, limiting production growth to about 1.5 Bcf/d this year, and then little more in the future, except for some blips during the winter when local demand can absorb incremental volumes. Bottom line for the U.S. supply/demand balance: Volumes needed for incremental LNG exports will need to come from somewhere other than Appalachia. Gas in that prolific region is bottled up by constrained pipeline capacity.

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  1. The energy transition gravy train has arrived. It’s time to get on board. Over the past year or so, two newly enacted laws have been radically increasing the government funding, subsidies, and tax credits available for all things to do with the energy transition. The Bipartisan Infrastructure Law includes $8 billion for regional clean hydrogen hubs, $1.5 billion for additional hydrogen initiatives, $10 billion to advance carbon capture technologies, and billions more for weatherization, smart power grids, nuclear and hydroelectric generation, and battery research. But that’s chump change compared to the Inflation Reduction Act (IRA), which has been estimated to include $391 billion in spending on energy and climate change out of the total $738 billion cost of the legislation. We are talking $60 billion for clean energy manufacturing (production tax credits and investment tax credits) and $30 billion in grant and loan programs for clean sources of electricity and energy storage. Plus a whole range of credits and subsidies for pollution reduction grants, appliance efficiency rebates, industrial emissions abatement investments, and environmental and climate justice block grants. Regardless of your energy transition politics, the billions are out there. It’s a once-in-a-lifetime opportunity to fund investments in energy projects that would never see the light of day without these programs.
  1. Permian crude oil pipeline capacity to Corpus Christi will soon max out. As we said in Prognostication #10 above, Corpus has been winning the crude oil export derby, accounting for 60% of U.S. exports today, and is expected to continue growing due to favorable VLCC shipping economics. But there’s a problem. Pipeline capacity from the Permian to Corpus is almost full. Up until 2019, the only pipe in that corridor was the Plains Cactus system, totaling 390 Mb/d. But in that year, Cactus II, EPIC Crude and Gray Oak all came online, increasing Permian-to-Corpus capacity to 2.5 MMb/d. All that new, highly efficient capacity with firm minimum volume commitments (MVCs) was the main impetus in the initial onslaught of Corpus exports. Today, flows on that capacity are running at about 2.2 MMb/d, or more than 85% full. We project that Permian production will increase about 500 Mb/d in 2023, with a lot of those barrels wanting to access VLCC shipping in Corpus. The only thing that will keep those pipes from filling in 2023 will be increasing Permian flows moving to Houston on the Wink-to-Webster line, operated by ExxonMobil Pipeline Co. But it’s only a matter of time before those Corpus pipes fill up. We hear that expansion-project talks are already in the works.
  1. Another round of steam crackers is coming to Gulf Coast ethane markets. The new Shell steam cracker in Pennsylvania that came online over the past few weeks was the last in a dozen new world-scale, mostly ethane-only petrochemical facilities in a wave of construction between 2018 and 2022. All these units added up to 30 billion lbs/yr of capacity needing about 800 Mb/d of ethane feedstock. Is that it? Not hardly. There is nothing that attracts new petchem investment better than a surplus of feedstock, and with NGL production increasing at a rate faster than crude or natural gas (Prognostication #8), expect new announcements to be hitting the streets in 2023. Already CP Chem and Qatar Energy have announced the Golden Triangle Polymers project, an $8.5 billion facility in Orange, TX, consisting of a 2.08 million metric tons/yr (4.6 billion lbs/yr) ethane cracker and two 1 million MT/yr (2.2 billion lbs/yr) HDPE units expected to start up in 2026. Rumors continue to swirl about one or more midstream companies jumping into the ethylene manufacturing business, including Energy Transfer and (although the company has denied it) Enterprise. Even with petchem margins down this year, ethane is still the most profitable feedstock, way above the naphtha feedstocks used in much of Asia and Europe. Don’t be surprised if more cracker announcements come over the next few months. It’s a business that will be growing as far as the eye can see.
  1. New natural gas pipeline/LNG supply projects are coming to debottleneck the Sabine River crossing. If you are not familiar with the geography, the Sabine River is the border between the southeastern corner of Texas and southwestern Louisiana, separating Beaumont/Port Arthur and Lake Charles. As we tabulated in Where It’s At, the problem is that most of the new LNG capacity is being built on the Louisiana side or in Port Arthur right next door, while much of the production growth will be coming from the Texas side (predominantly the Permian and Eagle Ford). As we covered in Prognostication #6, LNG terminals won’t be getting much of anything from the Marcellus/Utica due to maxed-out pipeline capacity. And although the Haynesville is quite productive, it can’t single-handedly keep up with all the LNG demand. So it all boils down to an emerging surplus of gas on the Texas side of the Sabine and a shortfall on the Louisiana side. Somebody needs to build a pipe! Or two!

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  1. The resurgence of energy security goals will breathe new life into energy project development opportunities. We all witnessed the radical shift in energy markets in the aftermath of February 24, when Russia invaded Ukraine. Literally overnight, the availability, source of production and, of course, the price of traditional sources of energy were front-and-center. In fact, those priorities swiftly overshadowed energy-transition goals. Until that day, a decade of energy abundance, a demand meltdown in 2020, and what looked like a budding recovery in 2021 had pushed energy security to the back burner. No longer. The energy security issue is now center stage and will remain so as we enter 2023 and the world struggles with the need to maintain affordable energy today while at the same time moving toward renewable fuels in the future. It is now clear to most everybody that we cannot reduce our reliance on fossil fuels until there are reliable, affordable alternatives available to meet the needs of an energy-hungry world. Wishful thinking won’t work. Suddenly, investment in infrastructure — particularly with the aim of enhancing energy security — is no longer off limits. And that has big implications for project developers. In 2023 expect to see a lot of projects that have been in limbo for years reemerge, repackaged as energy security developments.

That wraps up our 2023 Top 10 Energy Prognostications. If you strongly disagree — or even strongly agree — with any of this, please send us an email at info@rbnenergy.com.

New Year’s Resolutions                           .

So here are our recommendations for 2023 New Year’s resolutions: (1) keep it hoppin’, (2) don’t believe simplistic explanations of complex phenomena, and (3) when things get out of hand, fall back on the most famous quote from the most famous rabbit of all. Happy New Year!