If the ongoing global energy crunch is teaching us anything, it’s that decarbonizing the world’s economy may be even more difficult than many had figured. While a strong case can be made for reducing — or even slashing — greenhouse gas (GHG) emissions by shifting to low-carbon and no-carbon energy sources, the sheer magnitude of the undertaking means there are likely to be major setbacks and compromises along the way. Setbacks like having to turn to coal-fired generation this winter to help keep parts of the Northern Hemisphere warm and productive, and compromises like acknowledging that sometimes the wind doesn’t blow, the sun doesn’t shine, and utilities need to burn a lot more natural gas to make up the difference — assuming there’s enough gas around to burn, that is. One more takeaway from current events is that energy security in the form of being able to count on your counterparties is a pretty big deal. (We’re looking at you, Vladimir Putin.) With all that in mind, in today’s RBN blog, we examine the long-term outlook for energy and GHG emissions as the United Nations’ climate change conference in Glasgow, Scotland, looms on the horizon.
Posts from Housley Carr
There are a number of reasons why certain U.S. refineries might want to include waxy crude oil from Utah’s Uinta Basin in their crude slates — the highly paraffinic oil has a lot of neat qualities. But waxy crude can be a hard sell, mostly because, like bacon fat, it needs to be kept warm to remain in a liquid, flowable state. As a result, the vast majority of the waxy crude produced is driven in insulated tanker trucks to refineries in nearby Salt Lake City. Uinta producers have been making progress of late, however, in sending regular shipments of waxy crude in coiled and insulated railcars to a couple of Gulf Coast refineries. Existing terminals would support incremental growth, and a proposed new railroad out of the basin would allow far larger volumes to be efficiently railed to market. In today’s RBN blog, we continue our look at the prospects for a most unusual type of crude oil.
Given everything that’s happened lately on the ESG front — with a lot more expected — it’s safe to say that while hydrocarbons will continue to play an important role in the global economy for the foreseeable future, the companies that produce, transport and process crude oil, natural gas and NGLs will need to work much harder to minimize and mitigate their impact on the environment. Traditional energy companies have been scrambling to respond to the full-court press by investors, lenders and others to rein in and offset their greenhouse gas (GHG) emissions. In addition to establishing goals for slashing their GHGs, and taking steps to tighten their upstream, midstream, and downstream operations, they’ve offered and delivered “carbon-neutral” shipments of LNG, oil and LPG to overseas buyers, using “nature-based” carbon credits to offset their life-cycle emissions. Now, as we discuss in today’s RBN blog, there’s a big push by U.S. gas distributors and other buyers to shift to gas that’s been produced, gathered, processed and transported as cleanly as humanly possible.
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.
A long, long time ago — or, more precisely, in the spring of 2014, when WTI was selling for more than $110/bbl — a handful of exploration and production companies were convinced they were onto something big in southwestern Mississippi and east-central Louisiana. There, they believed, the Tuscaloosa Marine Shale (TMS) was poised to become the next Bakken, the U.S.’s premier shale play at the time, but even better for producers seeking more robust crude prices because of TMS’s very low gas-to-oil ratio — an oil cut north of 92%! –– and proximity to Gulf Coast refineries. While there had been a host of failed efforts by producers to wring out large volumes of premium-priced Louisiana Light Sweet (LLS) oil from the marine shale’s sedimentary silts and clays, the E&Ps felt in their bones that they were finally “cracking the code.” Then, at just the wrong time, came an oil price crash that set the whole industry back on its heels and activity in the TMS quickly slowed to a crawl. As we discuss in today’s RBN blog, an even smaller cadre of Tuscaloosa Marine Shale true believers is now banking on a production revival in the core of the play.
In the recently fervent efforts of oil and gas companies to mitigate their environmental impact and improve their standing with investors and lenders, they are progressively striving to cut their own emissions of greenhouse gases and to offset the GHG emissions that are unavoidable through the use of carbon credits. Cutting emissions from well sites, pipeline operations, refineries, and the like won’t be easy or cheap, but at the least the results are measurable and provable — before, we emitted X, and now we emit X minus Y. The true value of voluntary carbon credits is more difficult to calculate. Sure, each credit is said to equal one metric ton of carbon dioxide or its equivalent, but how do you really measure with any certainty how many metric tons of CO2 will be absorbed by 1,000 acres of preserved forest in Oregon, or how much methane won’t be produced by changing the diet of 1,000 cows in Wisconsin? And how can you be sure that slice of Oregon wouldn’t have been left in place anyway, or that the dairy farmer has actually changed what he’s feeding his herd? In today’s RBN blog, we look at voluntary carbon credits, concerns about their validity, and ongoing efforts to ensure that they actually accomplish the goal of GHG reductions.
There’s a lot to like about the unusual, waxy crude oil produced in the Uinta Basin in northeastern Utah. Low production costs, minimal sulfur content, next-to-no contaminants, and favorable medium-to-high API numbers. Oh, and there’s plenty of the stuff — huge reserves. The catch is that waxy crude has a shoe-polish-like consistency at room temperature, and has to be heated into a liquid state for storage and transportation. As you’d expect, refineries in nearby Salt Lake City are regular buyers; they receive waxy crude via insulated tanker trucks. They can only use so much though. Lately, a couple of Gulf Coast refineries have been railing in occasional shipments of waxy crude, but getting it onto heated rail cars involves a white-knuckle tanker-truck drive across a 9,100-foot-high mountain pass to a transloading facility. Now, finally, crude-by-rail access from the heart of the Uinta is poised to become a reality, offering the potential for much easier access to distant markets and, possibly, a big boost in Uinta production. In today’s blog, we provide an update on waxy crude and its prospects.
When fully loaded, a Very Large Crude Carrier (VLCC) sits so low in the water that it almost resembles an alligator swimming along the surface of a lagoon. Bearing the weight of 2 MMbbl of crude oil, plus ballast, fuel, crew, and provisions — not to mention the ship itself — two-thirds of an oil-laden VLCC is literally out of sight. You could say the same about the development of crude export terminal projects along the Gulf Coast: not much to see, maybe, especially during the disturbingly enduring COVID-19 era, but a lot is happening under the surface. In today’s blog, we discuss the status of onshore and offshore projects aimed at streamlining the shipment of U.S. crude oil to overseas buyers.
In the three years since Moda Midstream acquired Occidental Petroleum’s marine terminal in Ingleside, TX, the company has developed millions of barrels of additional storage capacity, connected the facility to a slew of Permian-to-Corpus Christi pipelines, and increased the terminal’s ability to quickly and efficiently load crude onto the super-size Suezmaxes and VLCCs that many international shippers favor. Moda’s fast-paced efforts have paid off big-time, first by making its Ingleside facility by far the #1 exporter of U.S. crude oil and now with a $3 billion agreement to sell the terminal and related pipeline and storage assets to Enbridge. The transaction, which is scheduled to close by the end of this year, will make Enbridge — already the co-owner of the Seaway Freeport and Seaway Texas City terminals up the coast — the top dog in Gulf Coast crude exports. Today, we discuss the Moda agreement and how it advances Enbridge’s broader Gulf Coast export strategy.
Many U.S. hydrocarbon production basins have experienced major ups and downs the past few years — the Haynesville, Eagle Ford, Bakken, and SCOOP/STACK, to name just a few. The Permian hasn’t been entirely immune from bad times either — crude oil and associated gas production there plummeted in the early days of the COVID-19 pandemic last year and again during the Deep Freeze in February this year — but it would be fair to say that the play’s Midland Basin has been among the energy industry’s surest bets during the Shale Era, with strong, highly predictable gains in output that producers and midstreamers alike can pretty much bank on. As a result, a number of gas-and-NGL-focused midstream companies have been taking the long view in their planning for new gathering systems, gas processing plants, and connections to a multitude of takeaway pipelines. In today’s blog, we discuss one company’s development of a now-massive and flexible hub-and-spokes network in the heart of the Midland.
In the past four years, natural gas production in the Permian Basin has doubled — from 6.6 Bcf/d in August 2017 to 13.4 Bcf/d now. To keep pace, the midstream sector has spent many billions of dollars on new gas gathering systems, processing plants, and takeaway pipelines, with virtually all of that investment backed by long-term commitments from producers and other market players. Thanks to that build-out, the Permian now has sufficient takeaway capacity — at least for another couple of years. But despite the 50-plus processing plants that have come online in the play’s Delaware and Midland basins in recent years, still more processing capacity is needed, as evidenced by the expansion projects and new plants that we discuss in today’s blog.
The volume of natural gas in storage and the flow of gas into and out of it are among the most closely watched indicators in the U.S. gas market. That makes sense, given that these numbers provide important weekly insights into the supply-demand balance, gas price trends, the impact of LNG exports, and any number of other market drivers. However, what’s often ignored by those not involved in the day-to-day physical gas market are the mechanics and economics of storage itself. Who uses gas storage, and for what purposes? What are the value drivers for a storage facility? Why are there different types of gas storage contracts? How much does storage cost, and what do storage rates reflect? Today, we explore these and other questions.
The high-tech space programs of Elon Musk, Jeff Bezos, and Sir Richard Branson may seem far removed from the down-to-earth business of producing and processing hydrocarbons. In fact, however, the multibillion-dollar efforts by SpaceX, Blue Origin, and Virgin Galactic to normalize space travel — and maybe even put the first men and women on Mars! — depend at least in part on some pretty basic oil and gas products, including regular jet fuel, highly refined kerosene, and LNG. Oh, and hydrogen too — or, more specifically, the liquid form of the fuel that has recently caught the attention of a number of old-school energy companies. In today’s blog, we look at what’s propelling the latest generation of space vehicles.
It’s often said that the offshore Gulf of Mexico is a different animal than its onshore counterparts, especially shale and tight-oil plays like the Permian and the Bakken. Decisions to invest in new production in the GOM aren’t based on crude oil demand and price forecast for the next two or three years; they’re based on expectations for the next two or three decades. Well, 30 years from now will be 2051, a year after Shell and a number of other energy companies have pledged to achieve “net-zero” carbon emissions. What does decarbonization mean for future development in the offshore Gulf, where the upfront capital costs are enormous and wells can be prolific producers for many, many years. In today’s blog, we discuss the final investment decision (FID) on Shell’s Whale project in the western Gulf of Mexico and the prospects for further development in the GOM.
Every day, midstream companies in North America transport massive volumes of crude oil, natural gas, NGLs, and refined products to market. Without their pipelines, economic activity would rapidly grind to a halt. Still, environmental critics and ESG-conscious investors and lenders are quick to point out that the commodities that midstreamers pipe are among the leading sources of greenhouse gas emissions, and that, at the very least, pipeline companies should be reducing or even offsetting the carbon dioxide (CO2) and other GHGs associated with operating their networks. That’s now happening in a big way — and in a variety of ways — as we discuss in today’s blog.