What began as a frenzy to build crude oil pipelines connecting US oil fields like the Permian basin to ports for export has resulted in more pipeline capacity than the crude to fill it.
In this episode of The Crude Report, our vice president Jeff Kralowetz and Petroleum Transportation North America editor Chris Baltimore go over the latest developments with the US Wink-to-Webster, Capline and DAPL pipelines, and the Trans Mountain expansion and Enbridge Line 3 replacement projects in Canada.
Jeff: Hello, everybody! I'm Jeff Kralowetz, welcoming you to The Crude Report, which is Argus' podcast on trends in the crude oil markets. There's so much going on with the Covid-19 Omicron variant, the Biden administration's decision to sell or lend 50mn bls of crude out of the SPR, and the balancing act that keeps going on between Opec+ and US shale producers, both of whom really have shown a lot of restraint in boosting drilling in the face of prices that had been rising right up until Friday.
But with all of that news, and we hope you'll continue to watch Argus' coverage of that, in times like this, it's really good to review some of the basic nuts and bolts of how the crude oil business works. And we're here to do that today with Chris Baltimore who's editor of one of my favorite publications at Argus, which is the weekly [Argus] Petroleum Transportation North America.
Every Saturday morning, Chris, I curl up with a coffee and a copy of your publication to try to understand what's going on with liquid pipelines, train routes, bark links, regulation, investment in the infrastructure sector that moves oil in North America. So we're really happy to have you and pick your brain a little on this podcast.
Chris: Thanks, Jeff, so much. Thanks. I'm glad to hear that I'm a part of your Saturday morning routine.
Jeff: Absolutely, absolutely. So I guess maybe the best thing to do is start with the biggest piece of infrastructure and that's the Capline. When I started at Argus about a million years ago, it was running over a million barrels a day of mostly light crude up from St. James, Louisiana to Patoka. Now it's reversed, of course, and it looks like it's starting commercial service in January. What can you tell us about what's going on with Capline and what its significance is to the overall sector?
Chris: Thanks, Jeff. Yeah, it seems like we've been talking about the Capline reversal for years. It definitely stretches back into the Pleistocene era of our coverage, but it looks like it's finally happening for real. As you mentioned, flows on that Capline, commercial flows, set to begin in January on the reverse line from Patoka to St. James, Louisiana.
Just a little bit of ancient history here. You know, Capline opened in 1967. That was before I was born just for the record. And, you know, it was a crude supply lifeline for midcontinent refiners at a time when the US was much more dependent on imports. And that Capline provided a key supply path from the LOOP (the Louisiana Offshore Oil Port) up to midcontinent refiners.
Things have changed, of course, with growing US domestic, you know, crude production. But in its original northbound configuration, Capline offered 1.2mn b/d of capacity, and it was the largest long-haul oil line in the continental US. Initial capacity on that reconfigured south-facing pipeline is dramatically lower, at just over 1,000 b/d.
Jeff: That piece is something that people ask about all the time. Why is it that a 1+mn b/d line going north is only gonna run about 100,000 b/d going south?
Chris: Yeah. Yeah, well, it's a good question, and it is a pretty staggering statistic there, kind of one-tenth of the capacity, but it really has to do with the number of operational pump stations that Capline's operators have decided to put in place to support demand, contracted demand on that line. So when Capline was operating in its original northbound mode, it had 16 pump stations running. At the moment, only 3 of those 16 pump stations had been configured to support the southbound service. Capline said that it wasn't feasible to reconfigure more of those pump stations based on shipper commitments that it got during an open season that it held for a reverse Capline capacity as well as the costs needed to do that work.
But it wouldn't be surprising to see that line's capacity increase over the next couple of years as Capline's owners figure out how to, you know, debottleneck the line, route more crude through the system. That reverse Capline, even from the outset, will offer more feedstock options for refiners in eastern Louisiana who have primarily looked to US offshore sour crudes as well as heavy imported crude from Venezuela and Mexico and Canada to fill those units. The US Gulf coast refiners in Texas have had more options to source US shale crudes from the Permian basin and the Bakken shale because of more pipeline connectivity, you know, the further west you get. Those Louisiana refiners have benefited less from that increased supply of inland domestic crude, which they'll get through the Capline.
Jeff: Great. Okay. So because of tight time, let's move directly to the Permian, which is, you know, looking to be the engine of any kind of US crude production growth going forward. There was a time just a couple of years ago when pipeline capacity from the Permian to the coast was pretty constrained and you had huge diffs between Midland and the coast, that all has changed. So where do we stand with the Permian pipeline capacity, do you think?
Chris: Yeah, it really does look like a Permian pipeline capacity has gone from famine to feast in recent years with the addition of so much capacity. It is hard to overstate the importance of the Permian basin there in Texas and New Mexico, which will drive the lion's share of output growth in the US over the next few years just because of its relative geographical advantage, its, you know pipeline connectivity to the Gulf coast, as well as the export markets there, as well as, you know, kind of more competitive extraction costs in the Permian than other basins like the Bakken or the Eagle Ford and such. According to Plains, one of the big midstream operators, the Permian will drive the vast majority of US crude output growth in coming years with the potential to increase by over 2mn b/d through 2025.
You'd mentioned the differentials and how different the differentials were back in 2018 or so when the spreads between the Permian basin's main pricing hub at Midland and prices at Houston made pipeline expansions an extremely hot topic. Producers were so eager to get their crude to market that they were railing it out of the Permian basin and hiring long-haul trucks to drive it halfway across the state to Corpus Christi, Gardendale, or other places where they could get it onto the pipeline network. Those kinds of heroic acts are no longer the norm after a handful of US crude pipeline expansions that survived Covid-19, kind of, cost-cutting blitz by US midstream companies are coming into service.
Those pipes come at the tail end of a massive multi-year midstream build-out that was pushed by record-high production and growing exports that added more than 2.5mn b/d of takeaway capacity from the Permian. The largest of those projects is known as Wink-to-Webster and its flows are ramping up on that line. That line is led by ExxonMobil – it's 1.5mn b/d of capacity from Wink to Webster. Other pipeline owners include Plains, Delek, Lotus Midstream, and Rattler Midstream. That system moves crude from Wink and Midland and the Permian to multiple locations near Houston, including Webster in Baytown with connectivity to Texas City and Beaumont. We would anticipate a lot of the liquidity on that line going straight to refiners rather than being traded in the open market. Keep in mind that ExxonMobil has its 560,000-b/d refinery in Baytown and also a quite large refinery in Beaumont.
But on top of Wink-to-Webster, we also have seen large additions from Cactus II, the Epic line, the Gray Oak pipeline. So there are fewer barrels these days looking to fill more pipelines and that hasn't been the best formula for full liquid pipelines. Adding to the mix is Energy Transfer, which continues to ramp up capacity on its Dakota Access pipeline from the Bakken shale across to Patoka and then a connecting pipeline down to Nederland, Texas. The capacity on the DAPL line has been increased by nearly 200,000 b/d to 750,000 b/d. And Jeff, that's going to put more Bakken crude into Nederland, Texas where it will be available for export as well as for feedstock use at Eastern Gulf Coast refineries.
Jeff: Okay. Thanks. That's a lot of balls in the air to keep track of. But it's interesting that you mentioned the DAPL expansion, and so there are expansions continuing to go on, but the consensus is that, in Texas anyway, you know, we've kind of overbuilt this system for a while. And what can you tell us about this problem or potential problem of pipelines running way below capacity or even empty?
Chris: Yeah, yeah. There's a lot of new pipe in the ground, for sure, that came online really just as a lot of those Covid-19-induced demand impacts were starting to take shape. So, you know, it's hard to get an exact read on individual pipeline flows, but sometimes it helps to kind of put things together. And looking at, kind of, the five biggest US midstream operators, it looks like flows are bouncing back from those Covid-19 lows. It looks like overall those flows kind of bottomed out in the first quarter of 2021 with the big five US midstream operators kind of coming in just below 11mn b/d per day there in the first quarter of 2021.
Now those flows have bounced back by about 15% in the third quarter, which is the most recent reporting segment that we've had. They bounced back to about 12.5mn b/d, but that's still well below the 14.3mn b/d, kind of, peak set in the first quarter of 2020 there before, you know, the pandemic hit. And we had a battle for market share between Saudi Arabia and Russia that sent crude prices tumbling to historic lows if you'll recall. So, you know, some infrastructure companies are struggling to fill their pipelines. You know, market rates are well below, kind of, the walkup tariff rates. Others seem to be more protected by long-term shipping deals that they might have inked before the pandemic set in.
Jeff: Okay. So one of the things that came to mind as you were describing all of that is at the beginning, you mentioned that the Permian capacity for production could rise to 7mn b/d by 2025. In other words, an extra 2mn b/d from where we are now. But the question I think is with all of this underutilized pipeline capacity, will the pipeline companies have patients to wait for that extra 2mn b/d, or are they likely to take some steps now to repurpose or deal with spare capacity?
Chris: Yeah, absolutely. That does seem to be a question that is in the background on a lot of these analyst calls. Midstream companies will get this question put to them. What about rationalizing your pipeline assets? What about, you know, selling them, repurposing them? There has been talk about, sort of, new renewable fuels, greener fuels like ammonia and such being able to fill some of the backlog. But there is this question about whether some of these assets can be repurposed to carry other products like gasoline or jet fuel or diesel or whether they would be taken out of service completely. You know, some companies like Magellan and Enterprise have discussed this idea in principle of re-purposing pipelines or rationalizing their assets. But they've been very cautious to date to make sure that we all know that these discussions are on a very theoretical plane and that moving on this issue really is not expected in the near term.
Jeff: Okay. And we are running out of time. Let's make the last question about Canada because an increasing amount of the crude that gets to the Gulf coast is coming from Canada, sometimes up to around 600,000 b/d. I know that you have some news on the Enbridge main line up there. And more generally, I guess, the question is, is congestion an issue of the past of the ability to get crude out of western Canada?
Chris: Yeah. Egress capacity out of western Canada has been a hot-button issue in recent years, you know, with an inspiring focus on rail to serve as a safety valve for what had been massive congestion on Enbridge's mainline pipeline network, that's the 3mn b/d network that really is the lifeline for WCSB production to reach, you know, the midcontinent and even with routing all the way to the Gulf coast. At one point, you know, Alberta's government resorted to curtailments, outfit curtailments and made massive investments in railed crude infrastructure to try to get a handle on, kind of, runaway differentials at the Canadian crude logistics hub at Hardisty, where prices were discounted as much as, you know, $50 under the US benchmark.
Those price disruptions have been mostly tamed by a big long-haul project that went into service in October and another one that's gonna be coming online late in 2022 or early 2023. You'll recall that the high-profile Keystone XL pipeline was suspended after running into a political roadblock with the Biden administration, but other high-capacity projects are still in the works that are gonna significantly boost Canadian egress capacity.
Yeah, you mentioned the big news. Late last week, Canadian regulators rejected a plan by Enbridge to shift its mainline pipeline network to contract carriage from common service. This would have been a big sea change in the way that Canadian crude moves across the mainline network. Enbridge now is gonna have to go back to the drawing board. It said that it could refile a fixed tariff tolling arrangement or even a cost of service tariff plan and is envisioning kind of a new regulatory review process, and that could conclude in 2023.
But Jeff, despite the setbacks, there still looks to be a fairly workable delivery system out of Canada. Enbridge, in October, started service on its Line 3 replacement project from Alberta to Wisconsin. That nearly doubles, you know, that line's capacity. And waiting in the wings is the TransMountain expansion that will add nearly 600,000 b/d of capacity from western Canada and is expected to be on stream late 2022, early 2023 that opens the door to more heavy crude movements to Canada's west coast and for potential export.
So on all, you know, the North American pipeline capacity puzzle looks, you know, manageable at the moment with plenty of capacity for all. That could change, of course, if North American producers decide to respond to rising crude prices by opening the taps. That seems a little less likely now that WTI prices are trading closer to $70 today. That's down significantly from even just about a week ago, Jeff, when prices were up above $80/bl. Prices are down significantly with the news of this new Omricon variant that you mentioned and its potential negative impact on global crude demand. But for now, it looks like things are mostly quiet on the pipeline front.
Jeff: Okay, Chris, this has been a really good rap of the major developments on infrastructure. And I just wanna remind people that you guys, every Friday night, put out the [Argus] Petroleum Transportation North America report, which is just a great summary of all the logistics news, the regulation, everything that affects how liquids petroleum liquids move around North America.
For all of you all who are listening, I wanna thank you for joining us. Please check out the [Argus] Petroleum Transportation North America. I think there are some sample copies available on our website at argusmedia.com or there's also a lot of free content on argusmedia.com webinars. These podcasts are posted there. So, and if you wanna take a look at any of our publications, please be in touch with us and we'd be happy to give you a closer look at what we're doing.
Finally, I guess, best wishes to everyone as we start this holiday season, and please join us again for the next edition of The Crude Report. Thank you.