Daily Energy Post Blog Articles

If Saudi Arabia and Russia flood the world with their crude oil in the midst of a global demand crisis, it would have impacts and implications far beyond crude. A ramp-up in Saudi and Russian oil production this spring would also increase their output of associated gas and NGLs. At the same time, the opposite will be happening in the Permian and other liquids-rich U.S. shale plays, where producers, stunned by sub-$25/bbl oil prices, already are pulling back on drilling and later this year will see their oil and NGL production gradually level off and eventually decline. All this is already turning the international LPG market on its head — just last week, U.S. propane exports plummeted by nearly 40% versus the prior week, to only 889 Mb/d. Today, we consider recent extraordinary market developments and their effect on the arb between Mont Belvieu and Far East LPG prices.

While the crude oil market meltdown has taken center stage in recent weeks, and for good reason, the natural gas market is bracing for its own fallout. The CME/NYMEX Henry Hub April futures price, which was already at a multi-year low, buckled last week, falling to as low as $1.602/MMBtu on March 23, and expired Friday at $1.634/MMBtu, the lowest April expiration settle since 1995. On its first day in prompt position, the May futures contract yesterday eked out a late-day, 1.9-cent gain that brought it back up near $1.70/MMBtu as traders continued weighing competing market factors. Gas futures earlier in March were initially buoyed by the assumption that the low oil-price environment would slow associated gas production — and it will, eventually. But that initial bullish sentiment was quickly usurped by the more immediate effects of demand losses resulting from the economic slowdown caused by COVID-19, as well as from mild weather. Today, we look at how these developments are shaping gas supply-demand fundamentals heading into the gas storage injection season.

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.

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.