With Environmental, Safety, and Governance (ESG) conscientiousness on the rise and the push to rein in greenhouse gas emissions gaining momentum by the day, many traditional players in the hydrocarbon sector are considering alternative energy sources to invest in. Two key questions they ask themselves when evaluating these options are: Does it make economic sense once you’ve factored in tax credits and other incentives, and can it be incorporated into North America’s existing energy infrastructure. Wind and solar power clearly fit the bill. So does renewable diesel, which also benefits from governmental programs and that it can be blended into petroleum-based diesel. Another alternative gaining traction is renewable natural gas, which is “produced” by capturing methane from landfills and wastewater treatment plants. Today, we discuss the potential and pitfalls of “the notorious RNG.”
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Daily energy Posts
It’s been a mantra in the energy industry for a few years now: more Canadian and Lower-48 crude oil needs to move to the Gulf Coast, with its bounty of refineries and export docks. And that’s been happening, thanks to a slew of new and expanded pipelines and new tankage. Similarly, new export capacity has been developed, and a number of refineries in Texas and Louisiana revised their crude slates to take advantage of what looked like an ever-rising supply of North American crude. Yet another piece of the puzzle will slide into place in January 2022, when crude oil — most of it heavy Western Canadian — will start flowing south on the newly reversed, large-bore Capline pipeline from the Patoka hub in Illinois to the impressive collection of terminals in St. James, LA. Today, we continue our series on the market impacts of Capline’s upcoming reversal on St. James, Louisiana refineries and crude exports.
Much like the world at large, the crude oil market has been healing from the ravages of COVID-19. Overall, market conditions are far better than they were in April 2020, when global oil consumption, crushed by pandemic-related lockdowns, slumped to 80.4 MMb/d, a 17% decline from the start of last year and a 20% drop from April 2019. Demand has been rebounding in fits and starts for a full year now — recovering from downturns is what markets do. But this recovery has gotten a big assist: 10 members of the Organization of the Petroleum Exporting Countries (OPEC), acting in concert with 10 non-members, have restrained crude oil production in a program unprecedented in scale and duration. Now, oil prices are high enough to revive activity by some producers outside the so-called OPEC+ group. For at least the rest of this year, in fact, the market looks like a steel-cage match between crude supply subject to coordinated management and supply governed only by raw market signals. Today, we look at oil-market projections from three important agencies and estimate demand for oil not supplied by the OPEC+ exporters.
Over the next few months, a variety of market players — crude oil producers, midstreamers, refiners, and exporters — will be making preparations for one of the most anticipated infrastructure additions in recent years. Actually, it’s not technically new; it’s the long-planned reversal of the 632-mile, 40-inch-diameter Capline, which for a half-century transported crude north from St. James, LA, to Patoka, IL. Line-filling will begin this fall and Capline will start flowing south from Patoka in January 2022, providing Western Canadian and other producers with new pipeline access to Gulf Coast markets. Upstream of Patoka, the impending reversal has been spurring the development of new pipeline capacity to supply the soon-to-be-southbound Capline, and in Louisiana, refiners and exporters have been making plans for the crude that will be flowing their way into St. James. Today, we discuss the broad impacts of the “new” Patoka-to-St.-James pipeline.
Today is a sad day for the world of oil tankers. Unless a miracle happens by 10 a.m. local time at the Hawaii Department of Transportation's Harbors Division, the last surviving iron-hulled, sail-driven oil tanker is headed to Davy Jones’ Locker. The once-proud, four-masted, 143-year-old windjammer will soon be scuttled by deliberately sinking her at sea off the shores of Honolulu. How could things have come to this? In today’s blog, we’ll take a trip down memory lane to explore how a spectacular, fully rigged oil tanker could have survived for so long, plying the oceans for this author’s former employer, only to be betrayed in her final years.
Plains All American has an extraordinary collection of crude oil gathering systems and shuttle pipelines in the Permian Basin, as well as full or partial ownership interest in a number of long-haul takeaway pipelines to the Gulf Coast and the Cushing hub. As important as many of these individual systems and pipelines may be, it’s the interconnectivity among these assets — and especially Plains’ crude oil terminals in Midland and other West Texas locales — that gives the midstream giant’s Permian infrastructure a value far greater than the sum of its parts. Today, we’ll discuss the important role that Plains’ two terminals in Crane, TX, play in balancing the midstream company’s Permian crude oil delivery network and providing destination optionality.
Every day, another 4.5 million barrels of Permian crude oil begin the journey from wells in West Texas and southeastern New Mexico to refineries in the U.S. and abroad. For most of that oil, it’s no simple trek. Not only does it wend its way through gathering systems and shuttle pipelines to nearby hubs, it often needs to be directed between terminals within those hubs to reach the specific outbound, long-haul pipe that will take it to where it needs to go. We get it — you probably don’t need to know about every nook and cranny in the multi-terminal hubs at Midland, Crane, Wink, and elsewhere in the Permian, but it sure would help to understand generally how the flow of oil to market works, and why a terminal’s ability to provide destination flexibility is so crucial. Today, we continue our series on Permian hubs and terminals with a real-world example of how a barrel of Delaware Basin crude oil moves to Corpus Christi, Houston, or Cushing.
Since the long-standing ban on most exports of U.S. crude oil was lifted more than five years ago, major ports and marine terminals along the Gulf Coast have been competing fiercely for the business of crude shippers. The primary weapons in this battle for barrels have been the abilities to provide easy pipeline access to the Permian and other key production basins, ample storage near the water for blending and staging, and top-notch dock facilities for quickly, efficiently loading crude onto tankers, the bigger the better. On that last point, for many shippers the vessel of choice is a 2-MMbbl VLCC, which typically offers the lowest per-barrel cost for long-distance oil delivery. Crude-laden VLCCs are “low riders” that need deep water, though, and so far only the Louisiana Offshore Oil Port can fully load one. Within a year, though, thanks to a long-awaited Corpus Christi Ship Channel dredging project now under way, marine terminals in Ingleside, TX, will be able to do the next-best thing: loading up to 1.6 MMbbl onto VLCCs, and thereby reducing the need for offshore reverse lightering. Today, we discuss the project to deepen the channel to 54 feet and its impact on crude exports.
Prior to COVID, crude oil and natural gas production in the U.S. had been on a tear, surging in tandem in the years following the 2014-15 price meltdown. But then the pandemic decimated domestic demand, crushing prices. Predictably, producers cut back production, particularly in crude-focused basins, and it was widely expected that associated gas from those regions would suffer in proportion. But that didn’t happen. Gas volumes have dropped somewhat, but not nearly to the extent that crude did. Said another way, the ratio of gas production to oil production has risen — and that’s been true at both the total U.S. level and in the primary unconventional basins for oil production. In today’s blog, we will look at the factors driving the trend of higher gas-to-oil ratios.
Crude oil production in U.S. shale and tight-oil plays still hasn’t recovered fully from the demand destruction wrought by COVID-19 in the last year or so. It could be argued, though, that producers in the offshore Gulf of Mexico (GOM) have faced even tougher times as they had to deal with not only pandemic-related staffing issues and project setbacks but the most active hurricane season on record. Offshore GOM production averaged only 1.65 MMb/d in 2020, a 13% decline from the previous year and the lowest since 2016. By August, production fell to less than 1.2 MMb/d, the lowest for that month in seven years. Many new projects were delayed as well, but things may finally be looking up, with first oil from a number of projects coming later this year or in early 2022 and final investment decisions (FIDs) on two major projects expected soon. Today, we discuss the wild ride that GOM producers experienced in 2020 and whether better days can be expected in the future.
Well, it’s been 365 days since the unthinkable happened: the price of WTI at Cushing went negative last April 20, and by a solid $37.63 a barrel at that. The insanity didn’t end there, though. The pandemic that many thought would be behind us in a season or two at most had a second wave, then a third and, some say, a fourth. U.S. refinery demand for crude oil, which plummeted by more than 3 MMb/d last spring, still has only recouped only half that loss. E&Ps, who shut in thousands of wells when oil demand and prices tanked, still are only producing 11 MMb/d — 2 MMb/d less than they were pre-COVID. LNG exports took a big hit too, another victim of demand destruction. As if all that weren’t enough, a couple of months ago, just as new vaccines were providing hope that everything would soon be returning to normal, the Deep Freeze put the Texas economy on ice and slowed production and refining once again. Strange times indeed. But we’re learning from it all, right? Today is the one-year anniversary of oil price Armageddon, so we take a look back at 12 months of market madness that no one could have predicted.
It is impossible to overstate the significance of the crude oil hub in Patoka, IL, to refineries in the Midwest. The seven-terminal hub, whose 80-plus above-ground tanks can hold more than 17 million barrels of crude oil, serves as the primary storage, blending, and staging site for a dozen refineries in five states with a combined capacity of more than 2.6 MMb/d. In other words, if the folks that keep Patoka running decide to take a couple of days off, Midwest refining would pretty much grind to a halt. And that’s not all: the southern Illinois hub also plays a critical role in sending crude oil south to the Gulf Coast. Today, we conclude our series on the Patoka hub with a look at the infrastructure within the facility’s boundaries and the pipes that transport oil out of it.
U.S. presidential transitions often bring policy changes, but few have been as dramatic and swift as the shift in energy policy that came with President Biden’s inauguration in January. Among his first acts after being sworn in was the signing of an executive order that revoked the Presidential Permit for TC Energy’s long-planned Keystone XL crude oil pipeline. Among other impacts, the move put on ice more than one-third of the Canadian midstream giant’s C$37 billion capital spending program for the 2021-24 period and unraveled TC Energy’s plan to balance its natural-gas-weighted pipeline portfolio with more crude oil pipes. So, what’s next for the midstreamer now that KXL is a no-go? In today’s blog, we’ll discuss highlights from our new Spotlight report on TC Energy which lays out how the company arrived at this juncture and where it goes from here.
Midland may be the king of crude oil hubs in the Permian, with its immense storage capacity and robust trading activity, but the hub in Crane, TX, is at least a prince — and a particularly interesting one at that. In addition to its 7 MMbbl of tankage for storing, staging, and blending crude (and another 1 MMbbl on the way), Crane offers a slew of inbound pipelines from both the Delaware and Midland basin, plus links to and from the Midland hub and a number of outbound pipelines to both the Corpus Christi and Houston markets. Just as important to know about, are the various intra-hub connections among Crane’s 10 terminals, because they reveal how you can get crude to pretty much wherever you need it to be. Today, we continue a series on crude storage in West Texas and southeastern New Mexico.
The steady growth in Permian crude oil production that everyone was banking on just a couple of years ago didn’t happen as planned. When COVID intervened, Permian oil output sagged and then stabilized at just over 4 MMb/d until last month’s Deep Freeze, when production plummeted and then quickly rebounded. Still, in anticipation of increasing output from the Permian, new takeaway-pipeline capacity from West Texas to the Gulf Coast was built out over 2016-20, as was new crude storage capacity at hubs in the Delaware and Midland basins to support the operation of the new lines. So, with all that construction, the Permian must be sittin’ pretty from a midstream infrastructure perspective, right? Don’t be too sure. From a big-picture perspective, the region has more than enough takeaway capacity, but there are strong indicators — and recent evidence — that in-region storage capacity hasn’t kept pace to be able to handle any hiccups (and worse) that can occasionally rattle the oil patch. Or maybe it’s just that folks don’t fully understand where the Permian’s storage capacity is, how it’s interconnected, and how it’s used. Today, we begin a blog series on crude storage in West Texas and southeastern New Mexico.
The Moda Ingleside Energy Center (MIEC) in Corpus Christi, the Enterprise Hydrocarbons Terminal (EHT) in Houston, and the Louisiana Offshore Oil Port (LOOP) have been loading more crude oil than any of their Gulf Coast competitors over the last year. In fact, they accounted for nearly half of the total oil exported. As many of the crude exporters have learned the hard way, leading the pack today is no guarantee you’ll still be out front six, 12, or 24 months from now. Despite the global pandemic and the market disruptions it has caused, a number of new export terminals and expansions to existing terminals are still under development, and all of them hope to draw barrels from their rivals. Today, we conclude our series with a look at planned capacity additions to Gulf Coast export facilities.