Just a few months ago, crude oil producers and marketers were wondering whether there would be enough marine terminal capacity along the Gulf Coast to handle the steadily increasing volumes of crude that would need to be exported over the next few years. Now, with WTI prices hovering around $25/bbl and producers slashing their 2020 drilling plans, expectations of rising U.S. production and exports are out the window. Instead, what may be shaping up is a fierce competition among the owners of existing storage facilities and loading docks to offer the most efficient, lowest-cost access to the water. Today, we continue our series with a look at two large Houston-area facilities: the Houston Fuel Oil Terminal and Seabrook Logistics Marine Terminal.
The collapse in WTI prices in March has been a crushing blow to the Permian, the Bakken and other U.S. shale plays that produce light, sweet crude oil. But as bad as sub-$25/bbl WTI prices are — especially for producers whose balance-of-2020 volumes aren’t at least partly hedged at higher prices — consider the record-low, $5/bbl prices facing oil sands producers up north in Alberta. Western Canadian Select, the energy-rich region’s benchmark heavy-crude blend, fell below $10/bbl more than a week ago, and on Tuesday WCS closed at $5.08/bbl. Producers, who already had been dealing with major takeaway constraints, are ratcheting back their output and planned 2020 capex, and slashing the volumes they send out via rail in tank cars. Today, we begin a short blog series on the latest round of bad news hitting Western Canada’s oil patch.
Like everything else in the world, energy markets are undergoing totally unprecedented convulsions. It seems as if everything that was working before COVID-19 is now broken, and an entirely new rulebook has been thrust upon us. Of course, it is impossible to know how crude oil, natural gas and NGL markets will play out over the next few weeks, much less in the coming years. But if we make a few reasonable assumptions, extrapolate from what we know so far, and crunch through a bit of fundamental analysis, it is possible to imagine what energy markets will look like after the worst of the coronavirus pandemic is behind us. One thing is for sure: things will not be anything like they were before. Where energy markets may be headed next is what we will conjure up in today’s blog.
The collapse in crude oil prices and subsequent cuts in producers’ planned 2020 capital spending make it crystal clear that drilling activity in the Bakken will be slowing. Still, even with less drilling, it will take at least a few months for crude production in the North Dakota shale play to fall by much, and Bakken producers will continue to depend on crude gathering systems to give their wells the most efficient, cost-effective access to takeaway pipelines and crude-by-rail terminals. Longer term, it’s important to remember that sweet spots in the Bakken’s four-county core have some of the best rock outside the Permian. Today, we continue our series with a look at another leading midstreamer’s existing and planned gathering systems, as well as its joint-venture central delivery point, shuttle pipeline and crude-by-rail facility.
In the stormiest market environment for crude oil in many years, it’s hard to find a spot where the sailing is smooth. If even-keel conditions exist anywhere in the oil-producing world today, it might be the offshore Gulf of Mexico, where producer decisions to invest in new platforms or subsea tiebacks are based on very long-term oil-price expectations and the production, once initiated, is steady. In the second half of the 2010s, Gulf producers significantly reduced the average breakeven prices needed to justify their most promising new investments — from more than $55/bbl back in 2015 to less than $35/bbl today. Given what’s happened to crude oil prices the past few days, however, it’s logical to wonder whether any of even the best prospective Gulf of Mexico projects will be sanctioned this year. Today, we discuss how cost-cutting and efficiency improvements have made the offshore Gulf a comparatively steady, growing base of U.S. crude oil production that so far has been less vulnerable than shale output to oil-price gyrations.
Statewide shelter-in-place orders, worldwide business shutdowns, market meltdowns, medical calamities. Much of what is going on right now is unprecedented in the modern era, and there are no guideposts to help predict what happens next to the world as we knew it. But in the boom-bust energy sector, it is déjà vu all over again. We have seen steep drops in prices, drilling activity and production enough times to have some idea about how this is likely to play out. Granted, this time around it is particularly bad, but that doesn’t change the sequence of events that we are likely to experience over the coming months and years. Today, we’ll look back at what happens to Shale-Era basins after a price collapse, focusing on the inherent lag between a major reduction in activity level and the inevitable production response.
Well, now we all know how it feels when the bottom falls out. In fact, it seems there is no bottom, with WTI crude at Cushing settling on Wednesday at $20.37/bbl, down $6.58/bbl. There is no point in belaboring the sad story here. You can read about pandemics, OPEC price wars and collapsed markets in every periodical on the planet. Likewise, there is no point in trying to predict what will happen next. Any pundit who tries to predict future prices in this environment is picking numbers out of the air at best. But at RBN, we are energy market analysts. As such, we are compelled to analyze something. And in these market conditions, there is one thing we can hang our hat on: No matter how bad things get, hope springs eternal. Thus, the market consensus is that things will be better a year from now, and even better a year after that. The implication? In a flash, crude is in steep contango, and that has repercussions for pipeline flows, regional price differentials and for storage — in production areas, at refineries, in VLCCs on the water, and especially at Cushing, OK, the king of oil storage hubs. Today, we examine one aspect of the chaos that now envelopes all aspects of energy markets.
Throw out your old production forecasts. Delete your pricing model spreadsheets. Push out the dates on your infrastructure project timelines. Or kill the projects all together. We’ve got a black swan on our hands here, folks. Perhaps a flock of black swans. And while we may see something like normal again in a few months, there is little doubt that it will be an entirely new normal. How do we even think through the wrenching transformations that are working through energy markets? At RBN, we don’t have any more answers than anyone else, but we do have a structured approach to market analysis supported by a set of spreadsheet models that are the core of our School of Energy, scheduled for April 14-15. We think that’s exactly the kind of approach necessary to make sense out of this volatile and chaotic market. And although we have cancelled the in-person conference, we’ve made the decision to GO VIRTUAL! Today, we explain our decision to move forward with the virtual School of Energy and discuss the new material we are incorporating into the curriculum to address today’s market realities.
With a number of U.S. producers slashing their drilling plans for 2020, crude oil production may flatten or even decline somewhat in the oil-focused basins over the next few months. Still, large volumes of crude — somewhere north or south of 3 MMb/d — will need to be exported from Gulf Coast docks for the foreseeable future to keep U.S. supply and demand in relative balance. That raises the questions of whether more export capacity will be needed, and if so, how much and when? The answers to these questions depend in large part on how much crude the existing marine facilities in Texas and Louisiana can actually handle. Today, we begin a series that details the region’s export-related infrastructure and examines its capacity to stage and load export cargoes this year and beyond.
The crude-oil price crash of the past couple of weeks is forcing producers in every U.S. shale play to reassess their drilling-and-completion plans for the balance of 2020. Still, while the pace of activity in the Permian, the Bakken and other major plays may slow somewhat in the coming months if crude prices stay low, the vast majority of the new wells that are drilled will need to be connected to crude gathering systems — ideally ones that offer producers and shippers a high degree of destination optionality. Today, we continue our series on crude-related assets in western North Dakota with a look at another leading midstreamer’s gathering system, and its link to the Dakota Access Pipeline and a nearby refinery.
It’s a new world, folks. The Saudis and Russians, who until a few days ago had been trying to prop up crude oil prices through supply management, are now engaged in an all-out war for market share. Crude oil prices are sharply lower. Three weeks ago, West Texas Intermediate was selling for $53/bbl and Western Canadian Select for $37/bbl; yesterday, they were selling for $34/bbl and $22/bbl, respectively. And things may get worse. All this has profound implications for North American production, but the effects on production in U.S. shale plays versus the Canadian oil sands will be very different. Today, we explain how the oil sands provide steady-as-she-goes baseload supply through pricing peaks and valleys while U.S. shale plays serve as a global swing supplier.
On Friday, global energy markets entered uncharted territory. Already facing declining demand due to the impact of COVID-19, markets then were dealt a body blow with the collapse of the OPEC-Plus alliance and the resulting prospect of a significant increase in supply. Saudi Arabia wanted to manage supply to balance against lower demand, but Russia was having none of it. Instead, reports from the OPEC-Plus meeting indicate that Vladimir Putin has declared war on U.S. shale. Then on Saturday, the plot thickened. Saudi Arabia made huge cuts in the price of its crude oil, presumably in a high-stakes move to bring Russia back to the negotiating table. Even though we are witnessing unprecedented market conditions, it’s not Armageddon. Crude oil will continue to be pumped, piped, shipped and refined. Most infrastructure projects under construction before the collapse in oil prices will be completed. The big question is, how will the market adapt? In today’s blog, we’ll begin an exploration of that question.
It’s been a good couple of years for many of the midstream companies active in the Bakken. Crude oil-focused drilling and completion activity has rebounded from a mid-decade slump, flows through their crude and gas gathering systems have been rising, and gas processing constraints that had threatened continued production growth have been on the wane. All that has led Bakken producers to plan for further gains in output in 2020 –– though that may change as the economic effects of the coronavirus become clearer. In any case, production growth is only possible if there’s sufficient gathering infrastructure in place to handle it. Today, we continue our series on crude-related assets in western North Dakota with a look at two midstreamers that have experienced big gains in their Bakken crude-gathering volumes.
The new, large-diameter crude oil pipelines coming online between the Permian Basin and the Gulf Coast grab all the headlines. They wouldn’t be nearly as valuable to producers, however, if it weren’t for a number of other, smaller projects being developed in West Texas to transport large volumes of crude from major gathering systems and storage hubs to these new takeaway pipelines. A case in point is Lotus Midstream’s recently unveiled Augustus Pipeline project, which will use a combination of new and existing pipe to initially transport up to 150 Mb/d of West Texas Intermediate (WTI), West Texas Light (WTL) and West Texas Sour (WTS) from Midland to Crane. When Augustus starts flowing late this year, crude delivered to the Crane hub could flow into the Longhorn Pipeline to Houston, or maybe the EPIC Crude or Gray Oak pipelines to Corpus Christi. Today, we discuss Lotus’s planned Midland-to-Crane project, and its significance for Midland Basin producers and the pipe’s owner/developer.
On Friday, CME/NYMEX WTI Cushing crude oil for April delivery closed at $44.76/bbl, down more than $16/bbl, or about 27%, since New Year’s Day. The declines in natural gas and NGL prices were not quite as severe, but only because those commodities were hit harder than crude during 2019. Even before COVID-19 landed on the market, energy prices were already under pressure from continued record production levels from U.S. shale, weakening demand, a mostly mild winter and a general investor pall over all things carbon. The threat of a global coronavirus pandemic was all it took to push things over the edge. So now what? Of course, nobody knows. But we can contemplate what this all could mean for energy markets, based on what we’ve seen in recent market statistics and price behavior. So that’s what we’ll do in today’s blog.