Well, 2025 is now in the books, allowing us time for reflection, resolution-making and pretending we always knew how the year would turn out. And unlike many, we also look into the rear-view mirror to see how we did with last year’s predictions. That’s what we’ll do in today’s blog.
In just a few days, President-elect Trump will return to office, determined to fulfill his many campaign promises, including his high-profile commitment to ease the regulatory burden on oil and gas producers so they can “drill, baby, drill.” Significantly ramping up production would likely bring down consumer prices for gasoline, diesel and other fuels — a noble goal — but it would also be at odds with the conservative, financially disciplined strategies that now guide many oil majors and oil-focused E&Ps. With the prospects for “drill, baby, drill” uncertain at best, and the correlations between oil prices, rig counts and production volumes less reliable than they used to be, how can we develop a production forecast? In today’s RBN blog, we explain what we do — oh, and we share our forecast with you, for free!
For the first 10 years of the Shale Revolution, it was a foregone conclusion: High prices stimulated more drilling, and more drilling meant higher production. It worked in both directions. When prices crashed, so did production. The correlation was great. The relationships were right on cue in 2014-15 when $100/bbl crude crashed to $30, rebounded to $60 by 2019, and wiped out in 2020 when the COVID meltdown hit. But then the market shifted. As prices ramped up in 2021 — eventually to astronomical levels in 2022 — the phenomenon of producer discipline kicked in, with E&Ps capping their drilling programs and returning a significant slice of their rising free cash flow to their shareholders. The near-term market implications of this new dynamic have been extensively documented in the RBN blogosphere. But what does it mean for the future? Especially for intrepid energy analytics companies (like RBN) that, by necessity, must project producer behavior far into the future to determine what production will look like next year, next decade and even further over the horizon. In this new RBN blog series, we will examine that dilemma, the assumptions RBN makes, and what our forecasts for the next few years look like.
Just a few years ago, when the Shale Revolution had matured into the Shale Era, the world settled into a nice groove, with crude prices generally rangebound between $40 and $70/bbl. As the U.S. looked to assume OPEC+’s role and evolve into the world’s swing supplier of oil, ramping up production when prices rose and slowing it down when they fell, it seemed reasonable to expect that market-driven responses would help maintain stability. Well, things haven’t turned out that way. COVID, the emphasis on ESG, a hydrocarbon-averse administration, and Russia’s war on Ukraine combined to put “reasonable expectations” in the trash. An entirely new set of expectations is emerging, and few metrics explain it better than today’s different-as-can-be relationship between crude oil prices and the U.S. rig count, as we discuss in today’s RBN blog.
Activity in Oklahoma’s SCOOP/STACK play has been picking up. In 2021, the number of active rigs there improved by about 30 — that’s a bigger gain than any U.S. hydrocarbon production basin except the Permian. On a percentage basis, the 160% year-over-year increase in the SCOOP/STACK rig count was exceeded — and just barely — by only a couple of other rich-gas regions: the Niobrara and Ohio portion of Marcellus/Utica. Is SCOOP/STACK really on the rebound and, if so, why? The answers are tied to commodity prices and the fact that the Oklahoma play offers producers both crude oil and “rich,” NGL-saturated associated gas. In today’s RBN blog, we discuss recent developments in the Sooner State’s premier production area.
Crude oil prices continued to increase this week, with WTI at Cushing closing Tuesday at $84.65/bbl, the highest level since October 13, 2014. The rise in crude since the spring of 2020 has been swift and almost relentless, interrupted only by pauses at $40, $60, and $70, when the market took breathers and seemed to say to itself, “We’re not done yet, right?” The question now is, can anything stop WTI from topping $90 and yes, the magic $100 mark — something that few would have predicted we’d see again so soon . The reality is, there are many factors driving crude prices higher but few holding prices down. In today’s RBN blog, we discuss what’s driving the rapid run-up in oil prices, whether $100/bbl WTI is a sure thing, and what happens if — when? — oil hits triple digits.
The market dislocations of the past year and a half really took the wind out of the sails of many U.S. hydrocarbon plays. Not the Permian, of course. Sure, production there declined some in the spring of 2020, but has been on the rebound ever since — aside from a brief, Deep Freeze-related downward spike back in February, that is. But the recovery in many other leading production areas was short-lived. Production in the Bakken has stayed close to flat lately, and output in the Eagle Ford has been slipping. The same is true in SCOOP/STACK, which only a few years ago was hailed as maybe the next big thing. What happened? And is there hope for a comeback? In today’s RBN blog, we discuss the once-hot Oklahoma play and its prospects.
Associated natural gas production out of the Permian Basin rebounded sharply a few weeks ago, indicating production curtailments that went into effect in May in response to low crude oil prices are coming back online. Just as abruptly as gas production dived in early May, it lurched upward in late June, nearly back to where it was before the shut-ins began. But the rig count has continued falling to a record low, and indications are that many of the wells drilled over the past few weeks have not been completed. The meager drilling and completion activity suggests that the natural declines of existing wells, which were temporarily exaggerated by the shut-ins, will now be felt — and felt for as long as rig counts remain depressed — not just in the Permian but also in other oil-focused basins. Daily gas production volumes in the Permian in the past 10 days or so already are slipping, despite shut-ins tapering. Today, we examine the latest production trends in the Permian and what it will mean for the gas production outlook.
