Posts from David Braziel

In the last 12 months, U.S. natural gas prices have touched highs not seen since the start of the Shale Revolution as well as depths previously plumbed only briefly during downturns in 2012, 2016 and 2020. Where will prices go next? Well, if we knew that, we wouldn’t be writing blogs. As we’ve seen in the past couple of years, there’s just too much going on in global markets to think you can know where gas prices will be 10 years, five years or even one year from now. But that never stopped us from trying. As we’ve done many times before, we’ll take a scenario approach — a high case and a low case. In today’s RBN blog, we’ll explore these scenarios for domestic natural gas prices and what sort of ramifications each would entail for other markets. 

In the last 12 months, U.S. natural gas prices have touched highs not seen since the start of the Shale Revolution as well as depths previously plumbed only briefly during downturns in 2012, 2016 and 2020. Where will prices go next? Well, if we knew that, we wouldn’t be writing blogs. As we’ve seen in the past couple of years, there’s just too much going on in global markets to think you can know where gas prices will be 10 years, five years or even one year from now. But that never stopped us from trying. As we’ve done many times before, we’ll take a scenario approach — a high case and a low case. In today’s RBN blog, we’ll explore these scenarios for domestic natural gas prices and what sort of ramifications each would entail for other markets. 

Back in the early 2000s, the outlook for energy security in the U.S. was bleak. Domestic oil production had been on a steady decline since 1985 and gas production was also well off its apex in the 1970s. M. King Hubbert’s concept of peak oil ignited fears of eventual energy scarcity. Given fossil fuels’ ubiquity underlying our entire Western economic and industrial structure, it’s no wonder that folks were concerned. But then the Shale Revolution changed everything. It’s often been said that necessity is the mother of invention and, after many trials and with considerable ingenuity, U.S. producers learned to wring massive volumes of previously trapped hydrocarbons from shale and gave the U.S. energy industry a new lease on life. But there are still limits on how much crude oil, natural gas and NGLs can be economically produced — and concerns lately that the best of the U.S.’s shale resources may have already been exploited. In today’s RBN blog, we examine crude oil and gas reserves: how they are estimated and what they tell us about the longevity of U.S. production.

Global crude oil markets are undergoing a profound transformation. But it is mostly out of sight, out of mind for all but the most actively involved players in the physical markets. On the surface, it’s a simple change in the Dated Brent delivery mechanism: Starting May 2023, cargoes of Midland-spec WTI — we’ll shorten that to “Midland” for the sake of clarity and simplicity — could be offered into the Brent Complex for delivery the following month. This change has been in the works for years. Production of North Sea crudes that heretofore have been the exclusive members of the Brent club has been on the decline for decades. Allowing the delivery of Midland crude into Brent is intended to increase the liquidity of the physical Brent market, thereby retaining Brent’s status as the world’s preeminent crude marker, serving as the price basis for two-thirds or more of physical crude oil traded in the global market. So far, the new trading and delivery process has been working well. Perhaps too well. For the past two months, delivered Midland has set the price of Brent about 85% of the time. The number of cargoes moving into the Brent delivery “chain” process has skyrocketed, and most of those cargoes are Midland. Is this just an opening surge of players trying their hand in a new market, or does it mean that the Brent benchmark price is becoming no more than freight-adjusted Midland? In today’s RBN blog, we’ll explore this question, and what it could mean for both global and domestic crude markets.

Since the advent of the Shale Revolution way back in 2008, U.S. production of natural gas liquids from gas processing has grown pretty much non-stop, from an annual average of 1.8 MMb/d 15 years ago to 5.9 MMb/d in 2022 — a 9% compound annual growth rate. Today, NGL production exceeds 6.1 MMb/d and that number might be even higher if the glut of supply wasn’t depressing prices and discouraging the recovery of a lot of ethane. All that production has major implications for domestic pricing, upstream economics, midstream infrastructure, and downstream consumers like petrochemicals, not to mention international markets, which now receive roughly 40% of U.S. output. In today’s RBN blog, we examine what’s causing NGL production to continually increase.

Yesterday’s Weekly Petroleum Status Report from the Energy Information Administration included an eye-popping statistic: 5 million barrels a day of crude oil were exported from the U.S. in the week ended August 12. It’s the highest U.S. export volume ever reported — and by a margin of nearly half a million barrels a day! But as huge as that top-line number is, and as many headlines as it’s sure to grab, it's not unexpected. Major changes in international crude markets, coupled with tectonic shifts in North American upstream and midstream, have conspired to push U.S. exports higher and higher. In today’s RBN blog, we examine the factors leading up to this point and what it means for crude markets in the U.S. and abroad.

In film and television, the “boxed crook” trope is where a condemned person is sought as a last-ditch effort to pull off some impossible mission or overcome a formidable opponent. In return, the convict is typically offered amnesty or other consideration by the operatives in charge. Millennials will probably think of the recent Suicide Squad movies. For Generation X, The Rock starring Sean Connery was a great example. And for the boomers, it was The Dirty Dozen. Our current situation in the U.S. energy sector may not be quite as thrilling as those movies but the same plot elements exist. In today’s RBN blog, we discuss the predicament faced by industry and political leaders and begin to sort out the various proposals to put a lid on prices and restore energy security.

The Federal Energy Regulatory Commission (FERC) issued two new statements of policy February 17 regarding the certification of new pipelines and the assessment of greenhouse gas (GHG) impacts. Together, the two updates reflect a more meticulous regulatory environment and a stricter adherence to policies that midstreamers must comply with in an effort to avoid lengthy and expensive court challenges that have become more commonplace recently. The guidelines will affect most new projects within FERC jurisdiction and, among those, some of the biggest impacts will be felt in the U.S.’s rapidly expanding LNG sector — the terminals themselves and the pipelines that deliver feedgas to them. That could be cause for concern as Russia’s war on Ukraine has exacerbated an already precarious gas situation in Europe and a global LNG supply crunch. In today’s RBN blog, we explain the impact of FERC’s latest guidance on pipeline certification and GHG policy with regard to the LNG sector.

The world is in desperate need of more crude oil right now and anybody with barrels is scouring every nook and cranny for any additional volume that can be brought to market. Some of that may come from increased production, but the oil patch is a long-cycle industry, just coming off one of the most severe bust periods ever, and it will take time to get all the various national oil companies, majors, and independents rowing in the same direction again. For now, part of the answer will be to drain what we can from storage — after all, a major purpose of storing crude inventories is to serve as a shock absorber for short-term market disruptions. To that end, the U.S. is coordinating with other nations to release strategic reserve volumes to help stymie the global impact of avoiding Russian commodities. Outside of reserves held for strategic purposes though, commercial inventories have already been dwindling as escalating global crude prices have been signaling the market to sell as much as possible. Stored volumes at Cushing — the U.S.’s largest commercial tank farm and home to the pricing benchmark WTI — have been freefalling for months, which raises the question, how much more (if any) can come out of Cushing? In today’s RBN blog, we update one of our Greatest Hits blogs to calculate how much crude oil is actually available at Cushing.

Russia’s war on Ukraine turbocharged global crude oil prices and spurred price volatility the likes of which we haven’t seen since COVID hit two years ago. The price of WTI at the Cushing hub in Oklahoma — the delivery point for CME/NYMEX futures contracts — has gone nuts, and the forward curve is indicating the steepest backwardation ever. In other words, the market is telling traders in all-caps, “SELL, SELL, SELL! Sell any crude you can get your hands on. It’s going to be worth far less in the future.” So anyone with barrels in storage there for non-operational reasons is pulling them out, and fast! In today’s RBN blog, we look at the recent spike in global crude oil prices and what it means for inventories at the U.S.’s most liquid oil hub.

It ain’t easy being a midstreamer lately. Well, it’s probably never been easy, but these days trying to get a pipeline project to the finish line might feel a bit like Sisyphus from Greek mythology, forever pushing a boulder up a hill, filled with obstacles and setbacks. That hill has leaned ever-steeper in the past several years as turnover among FERC’s commissioners delayed project reviews, courts reversed a number of FERC approvals, and public opposition to pipeline projects increasingly delayed progress, even resulting in cancelations. And two weeks ago, the approval process was made tougher still when FERC announced new statements of policy regarding project certifications and greenhouse gas impact assessments. The proposed changes have caused a lot of anxiety among midstream companies, although in many ways FERC just declared as policy what was already happening on a case-by-case basis. But midstreamers shouldn’t panic. In today’s RBN blog, we explain the commission’s new guidance and how much impact it will really have.

In the early days of the Shale Revolution, merger-and-acquisition activity in the midstream sector was happening at a frenetic pace. That frenzy peaked with crude oil prices in 2014, then petered out over the next five years before hitting bottom in COVID-impacted 2020, when abysmal demand and commodity pricing hampered prospects for the production and transportation of oil, natural gas and NGLs. In those dark days, it seemed the only deals getting done were for bulk orders of hand sanitizer and toilet paper from Amazon. Now, with energy prices soaring and energy companies regaining some of their pre-pandemic luster, the pace of deal-making in the oil patch in 2022 looks poised to maintain the momentum that carried through the end of 2021. But buying or marketing midstream assets isn’t nearly as simple as ordering through your Amazon Prime account. Considerable effort is put into the strategy of selling and the diligence of purchasing and, for the uninitiated, the process can be daunting. In today’s RBN blog, we continue our series on midstream dealmaking with a look at what to expect in a sales process.

Any time there’s a step-change in technology, it presents intrepid industrialists with tremendous opportunities. Just looking at U.S. history, this has played out many times, with railroads, oil, automobiles, computers, and the internet being a few obvious examples. The Shale Revolution provided significant opportunities of its own, not just for the savviest producers but for midstreamers who jumped at the chance to develop the pipelines, gas processing plants, fractionators, and other infrastructure that was desperately needed to transport and process rapidly growing volumes of crude oil, natural gas, and NGLs. Master limited partnerships (MLPs) led the way, boosted by their advantaged access to capital, but they got an important assist from private-equity-backed developers, who were willing to take big risks in the hope of creating successful businesses. In today’s RBN blog, we continue our look at midstream dealmaking — and midstreamers’ prospective role in the coming lower-carbon economy — this time with a focus on the private equity (PE) side.

The Shale Revolution created an unprecedented need for midstream infrastructure of every sort — gathering systems, processing plants, storage hubs, takeaway pipelines, fractionators, export terminals, and more — all with the aim of connecting new hydrocarbon supply to demand. Throughout the 2010s, the scope and urgency of this midstream build-out opened up tremendous opportunities for the master limited partnerships, private-equity-backed developers, and other entities with the management skills, financial wherewithal, and dexterity to make these massive projects happen. Now, much of the Shale Era’s required new infrastructure is in place — and COVID and ESG have slowed new-project development to a crawl — putting many MLPs in a bind and leaving private equity firms to wonder where they should invest their money next. Well, there may be an even better set of new opportunities on the horizon — all related to the coming energy transition — and, as it turns out, midstream developers with hydrocarbon experience are uniquely positioned to lead the way. In today’s RBN blog, we discuss how the project-development model that drove the midstream sector’s growth over the past decade is poised for potentially lucrative re-use in the 2020s and beyond.

With the UN’s Climate Change Conference (COP 26) in Glasgow just over a month away, it’s natural to reflect on the progress achieved since the Paris Agreement (signed at COP 21), which is approaching its sixth anniversary. In the past half decade, the world has taken tremendous strides toward decarbonization – not only in rhetoric, but in real and substantial investment. Green hydrogen and carbon capture are among the notable solutions many are pursuing to that end. But perhaps no green business has been in the spotlight as much recently as renewable diesel. Low-carbon fuel standards have spurred a lucrative renewable diesel market that refiners are lining up to access, with units being built and planned across North America. The nationwide buildout is being underwritten by the states that have enacted policies to induce low-carbon solutions, and while the Golden State is paramount among them, Californians are not alone. The largess being generated by those policies is so substantial that it will have an impact on and may incubate other low-carbon technologies that can be paired with renewable diesel to create even lower-carbon fuel sources and capture more of the credits that are ultimately driving the economics of the energy transition. In today’s RBN blog, we identify key manufacturing centers for low-carbon fuel supply growth, the at-times lengthy route the fuels may take to LCFS markets, and the economic incentive structure that justifies all those costs.