The midstream crude oil sector enters the third-quarter earnings season stuck, well, in the middle between surging commodities prices and the producers' fiscal discipline that has prevented much of a trickle-down to the companies that move, process and store the liquids.
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To borrow a cliché, the industry finds itself in a veritable no man's land -- caught between the separate pulls of growing global crude oil demand and the investors' demands to invest more in energy transition projects, such as carbon capture, hydrogen in more. All the while, the North American midstream space is relatively short on cash and capital compared to their upstream peers.
"Midstream is out of favor, and it's largely because midstream has not benefited much yet from the commodities increases," said Matthew Taylor, an energy analyst with Tudor, Pickering, Holt & Co. "And there may not be materially more volumes because, so far, upstream is holding the line on modest growth."
Taylor prefers to use another cliché, arguing the midstream space is sitting in both a literal and metaphorical "calm before the storm."
"It's the calm before the storm, and that storm could be significant weather that causes spikes in prices, and also the calm before the storm before we see producers react," Taylor said.
A repeat, for instance, of the mid-February winter storm Uri would come amid much higher crude oil and natural gas prices late this year or in early 2022.
As the quarterly earnings calls pick up, analysts said they are looking for guidance on hikes in spending and production volumes. While fiscal discipline will remain the driving force, producers will still look to add incremental drilling and production growth, especially in the Permian Basin and even in western Canada now that Enbridge has added more pipeline capacity with the recent completion of the Line 3 replacement project.
"We may see a change of tone come 2022 guidance," said AJ O'Donnell, product team director for East Daley Capital. "With an $80 price, it's hard not to add rigs in the Permian."
Indeed, WTI at Midland, Texas, has averaged $81.71/b so far in October -- near seven-year highs -- up from an average of $53.10/b in January, S&P Global Platts assessments show. Front-month NYMEX WTI was trading at $82/b on Oct. 15, while ICE Brent was approaching $85/b.
US crude production peaked at an all-time high of nearly 13 million b/d in early 2020 before the pandemic, but is back up to about 11.4 million b/d, according to the US Energy Information Administration. The Permian has recovered to roughly its previous high of 4.8 million b/d, but the Bakken Shale and Eagle Ford Shale, for instance, are each more than 300,000 b/d below their pre-pandemic levels.
As TotalEnergies CEO Patrick Pouyanné said Oct. 14 during an S&P Global Platts conference, "They have been disciplined. But, at $85, I suspect they will forget. That's why we have cycles."
While midstream companies are keen to announce new energy transition projects, the focus is much more on potential projects and much less on committing major dollars through final investment decisions.
Pipeline operator TC Energy and electric vehicle manufacturer Nikola Corp., for instance, just announced they will collaborate to develop large-scale hydrogen production hubs in the US and Canada. But they are not yet committing to anything definitive.
Likewise, both Corpus Christi, Texas and the Mont Belvieu area of Houston aim to develop major carbon capture and storage hubs, but everything is aspirational for now. In Canada, TC and Pembina Pipeline look to develop a massive "Alberta Carbon Grid."
But these energy transition efforts are early and the companies are hesitant to commit the billions of dollars without firm government incentives and ample revenues, said Colton Bean, also of Tudor, Pickering, Holt & Co.
"They're starting to think about these things and realize that running a 100% crude pipeline business may not be viable in whatever years from now," Bean said. "But the scale of the businesses is such that they can't pivot in a year or even five years."
With much of the US over-piped and the emphasis on financial discipline, analysts said it is a boring time for big new projects.
"The days of big, new greenfield projects are behind us for now," Taylor said.
The last of the big Permian long-haul crude pipelines is nearly complete in the ExxonMobil-led Wink to Webster Pipeline bringing more volumes to Houston and taking some crude-exporting market share from the Port of Corpus Christi.
O'Donnell said the Wink to Webster system was moving about 400,000 b/d as of June, but it will ramp up much more in the fourth quarter as the final segments are completed and new contracts kick in. The pipeline eventually will have a capacity of nearly 1.5 million b/d of crude.
Also bringing more crude to the US Gulf Coast -- as early as January -- is the expected completion of the Capline Pipeline reversal into Louisiana. Since Plains All American Pipeline canceled the Byhalia Pipeline project that would have connected the Diamond Pipeline from Cushing, Oklahoma to Capline, analysts are looking for more commentary on how the companies might solve that logistical problem.
And then there is the issue of when and if the race will resume -- after coming to a screeching halt during the pandemic -- to build deepwater crude-exporting terminals offshore of Texas. If there is one to watch, analysts said, it is Enterprise Products Partners' Sea Port Oil Terminal, called SPOT, offshore of the Houston Ship Channel.