This time last year, Appalachian natural gas production was approaching a steep springtime ledge as regional prices sank below economic levels and producers responded with real-time shut-ins. This year to date, regional gas prices have averaged $0.80-$0.90/MMBtu above 2020 levels for the same period, and production has been averaging more than 1 Bcf/d above year-ago levels. If production holds steady near current levels, the year-on-year gains would just about double to ~2 Bcf/d by mid-May, which is when the bulk of the springtime curtailments first took effect in 2020. This, just as Northeast demand takes its seasonal spring plunge, which means regional outflows are poised to rise in the coming weeks, potentially to record levels. How much more can the Appalachian takeaway pipelines absorb? In today’s blog, we continue our analysis of outbound capacity utilization, this time focusing on the routes to the Midwest.
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Daily energy Posts
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.
Production of synthetic crude oil that is processed from Alberta’s oil sands reached record highs at the end of 2020 after touching on two year lows just four months earlier. However, these highs could be undermined and sink to four-year lows for a short period of time this spring with what appears to be a heavier than usual slate of maintenance work on three of Alberta’s four upgraders, the immense processing units that produce synthetic crude oil from bitumen. In today’s blog, we take a closer look at the upgraders, the timing of maintenance, and what this might mean for synthetic crude oil production and exports.
The crude oil hub in Patoka, IL, is in many ways a smaller version of the hub in Cushing, OK. Like its larger sibling, Patoka receives a broad variety of crudes from Western Canada, the Bakken, and other production areas, stores and blends oil, and sends it out to refineries and Gulf Coast terminals tied to export docks. In Patoka’s case, there are only five major incoming pipelines that directly connect to the hub, but many of them receive crude from a number of upstream systems, some as far away as the Alberta oil sands. Important for Patoka’s future, a few of the pipelines feeding the hub are being expanded. Today, we continue our series on the second-largest oil hub in PADD 2 with a look at the pipelines that flow into Patoka and the sourcing of their crude.
The competition for barrels and the top-spot ranking among the Gulf Coast’s crude oil export terminals is like any good PGA tournament or NASCAR race, with lots of changes in who’s out in front and the ever-present possibility of a surprise — the export-market equivalent of an eagle at the last hole at the Masters or a spin-out and multicar crash on the last lap at the Daytona 500. A couple of years ago, in the first quarter of 2019, the Enterprise Hydrocarbons Terminal in Houston was at the top of the crude-exports leaderboard, followed by Energy Transfer’s Nederland Terminal and Moda Midstream’s facility in Ingleside, TX. Since then, Enterprise has ceded the #1 spot to Moda, volumes out of Nederland have slowed to a trickle, and the Louisiana Offshore Oil Port, with its unique ability to fully load Very Large Crude Carriers, has rocketed to #3. Today, we continue our series on Texas and Louisiana’s oil export facilities with a look at the Gulf Coast’s second- and third-largest terminals by export volume.
The crude oil hub in Cushing, OK, is larger and grabs the headlines, but don’t you forget about the Patoka hub in south-central Illinois. It plays critically important roles in receiving Western Canadian, Bakken, and other crude, distributing it to a slew of Midwestern refineries, and directing oil south to the Gulf Coast on the Energy Transfer Crude Oil Pipeline to Nederland, TX — and soon on Capline to St. James, LA, when reversed flows on that large-bore pipe begin in early 2022. Better still, there are great stories behind the development of the Patoka storage and distribution hub and how it works. Today, we begin a series on the second-largest crude oil hub in PADD 2 and why, with the upcoming Capline reversal and other changes, the hub is more relevant than ever.
Week by week, more than 20 terminals along the U.S. Gulf Coast export crude oil, but nearly half of the total export volumes are being loaded at just three facilities: the Moda Midstream terminal near Corpus Christi, the Enterprise Hydrocarbon Terminal in Houston, and the Louisiana Offshore Oil Port (LOOP) off the Louisiana coast. What gives these “Big 3” their edge? Location? Pipeline connectivity? Storage capacity? Loading rate? The answer, of course, is “all of the above.” There is more to the story, though, and other terminals are angling to become bigger players, presumably at the expense of the Big 3 themselves. Today, we begin a series on Texas and Louisiana’s largest oil export facilities, what they offer, how they’ve fared, and what they’re planning next.
When it finally came online in mid-2017, the Dakota Access Pipeline was a lifesaver for Bakken crude oil producers. For years, they had suffered from takeaway-capacity shortfalls that forced many shippers to rely on higher-cost crude-by-rail, sapping producer profits in the process. Then came DAPL, which provides straight-shot pipeline access to a key Midwest oil hub, and its sister pipe — the Energy Transfer Crude Oil Pipeline (ETCOP) — which takes crude from there to the Gulf Coast. Problem solved, right? Not exactly. Now, there’s at least an outside chance that a shutdown order is issued as soon as early April in connection with the ongoing federal district court process, with the timeline for a physical closure of the pipe still to be determined. A shutdown may last for only a few months but could potentially last much longer. Where does this uncertainty leave Bakken producers, many of whom have been hoping to benefit from the recent run-up in crude oil prices by ramping up their output this spring? Today, we discuss recent upstream and midstream developments in the U.S.’s second-largest shale/tight-oil play.
It’s never easy in the commodity world, and despite oil prices comfortably above $50/bbl across the Permian, a new worry has come to the fore as we start the second month of 2021. No, it’s not a Reddit movement focused on the oil market, not even an OPEC+ action this time. The latest news that has wildcatters muttering through clenched teeth came from Washington D.C., where the Biden administration recently announced a pause on leasing federal lands for oil and gas development. While it’s far too early to discern what this decree — or future actions — will mean for the Permian, we get the sense that the headlines aren’t capturing the nuances of drilling activity in West Texas and southeastern New Mexico. In our view, at its worst, a long-term ban on drilling on federal lands would produce some clear winners and losers, while the near-term impact is potentially just a ripple in the ocean. Today, we examine what the latest drilling data from the Permian tell us about the possible outcomes of the new administration’s recent actions.
Sure, there was at least some hope among Keystone XL’s supporters that President Biden might back away from his promise to kill the much-maligned crude oil pipeline project. After all, KXL developer TC Energy had done all it could to make the 1,210-mile project more palatable to the incoming administration by making Canadian First Nation groups partners in the project, reaching a favorable labor agreement with the four U.S. unions that would build the pipeline, and, most recently, committing to invest in renewable energy to power KXL’s pumps and other equipment. But it wasn’t enough, and now, with Biden’s decision to revoke the project’s Presidential Permit, it appears that the Alberta-to-Nebraska pipeline is all but dead, and that Western Canada will need to get by without its 830 Mb/d of southbound capacity. The looming question now is, what does that mean for Alberta’s producers — particularly those that have signed up for more than 500 Mb/d of space on KXL? Today, we discuss what’s ahead.
U.S. crude oil imported from Western Canada averaged almost 3.6 MMb/d in the first 10 months of 2020 and accounted for 60% of total imports over the period. That’s some growth! Ten years ago, Canada was sending less than 2 MMb/d south and contributing only 21% of total U.S, import volumes. Alberta oil sands producers are planning for more production and export growth through the 2020s, with most of the incremental volumes bound for Midwest and Gulf Coast refineries and export docks. If that happens — and there’s no certainty it will — more north-to-south pipeline capacity through the U.S. heartland will be needed. Today, we continue our series on the efforts to expand or reverse crude oil pipelines between the U.S./Canada border and the Gulf of Mexico.