RBN Energy Blogcast RBN Energy

No doubt about it, most of the headline-grabbing oil and gas M&A activity lately has involved large, publicly owned producers gobbling up other good-sized E&Ps, lock, stock and barrel. But there are other ways to increase scale and improve operational efficiency, as evidenced by privately held WildFire Energy’s bolt-on acquisition frenzy in the relatively sleepy northeastern Eagle Ford, aka the East Eagle Ford. In less than three years, with one bolt-on acquisition after another, WildFire — named in anticipation of the company’s aggressive expansion strategy — has morphed from a small player in the often-overlooked area into one of the largest producers there, with a laser focus on maximizing returns to its management and private-equity owners. In today’s RBN blog, we’ll look at the E&P and its rapid rise. 

The Nederland/Beaumont crude oil hub has been somewhat overshadowed recently by other Gulf Coast crude export hubs despite hosting America’s largest refinery, a handful of export terminals and pipeline links to the prolific Permian Basin. But while plans to build one or more deepwater crude export terminals could mean big changes for the Gulf Coast hubs, the Nederland/Beaumont area isn’t standing still. In today’s RBN blog, we discuss what’s ahead for the region and its emergence as a leader in NGL exports. 

Passage of the Inflation Reduction Act (IRA) in August 2022 was intended to unleash a wave of clean-energy initiatives, from hydrogen and renewable fuels to electric vehicles and large-scale carbon-capture projects, all part of the Biden administration’s plans to reduce carbon dioxide (CO2) emissions and move the U.S. closer to a net-zero economy. But while billions in federal financing and tax credits have helped move many projects forward, they can only advance as fast as permitting, regulations and economic reality will allow. In today’s RBN blog, we look at the surge in proposed carbon-capture projects since passage of the IRA, where they are in the review process, and how the pace of permitting at the federal level compares with the states that have primacy over their own sequestration wells. 

There’s never been any reason to question the drivers for energy infrastructure development — until now.  Historically, the drivers were almost always “supply-push.” The Shale Revolution brought on increasing production volumes that needed to be moved to market, and midstreamers — backed by producer commitments — responded with the infrastructure to make it happen. But now things seem to be different. U.S. energy infrastructure investment is soaring across crude oil, natural gas and NGL markets and, as in previous buildouts, midstreamers are bringing on new processing plants, pipelines, fractionators, storage facilities, export terminals and everything in between. We count nearly 70 projects in the works. But crude production has been flat as a pancake, natural gas is down, and lately NGLs are up — but as you might expect, only in one basin: the Permian. So what is driving all the infrastructure development this time around? In today’s RBN blog, we’ll explore why that question will be front-and-center at our upcoming School of Energy: Catch a Wave. Fair warning, this blog includes an unabashed advertorial for our 2024 conference coming up on June 26-27 in Houston. 

The four deepwater crude oil export projects under development along the U.S. Gulf Coast are getting closer to receiving their regulatory go-aheads after years of planning and millions of dollars spent. In fact, Enterprise’s Sea Port Oil Terminal (SPOT) received its license in April. These projects have sparked commercial and wider market interest because of the many benefits they may provide — including the ability to fully load 2-MMbbl Very Large Crude Carriers (VLCCs) without any reverse lightering. In today’s RBN blog, we highlight key insights from our new Drill Down Report on the four projects, the potential benefits and the challenges they face. 

Some of the most prolific, crude-oil-saturated rock in the Permian’s Delaware Basin and Central Platform comes with a nasty complication — namely, associated gas with very high levels of hydrogen sulfide (H2S) and carbon dioxide (CO2). But rather than walking away from all those potential barrels, one midstream company saw the treatment of high-H2S, high-CO2 gas as a market niche worth pursuing. Backed by commitments from Black Bay Energy Capital and an area E&P, Piñon Midstream has been expanding a system in southeastern New Mexico that not only gathers the super-corrosive gas and removes almost all the H2S and CO2, it also permanently sequesters the stuff deep underground through a pair of 18,000-foot-deep, Class II injection wells. In today’s RBN blog, we will provide an update on Piñon’s Dark Horse Treating Facility and the company’s plan for a further build-out of its sour gas system.