The run-up in U.S. production of natural gas liquids over the past 10 years spurred the development of a whole lot of infrastructure. More pipelines to transport mixed NGLs from production areas to NGL storage and fractionation hubs, especially Mont Belvieu, TX. More fractionators to split y-grade into ethane, propane, and other “purity” products. And, specifically for ethane — the lightest, quirkiest, and most plentiful NGL — a number of ethane-only steam crackers were built along the Gulf Coast to take advantage of the new supply abundance, as were ethane-only pipelines, export terminals, and a whole new class of cryogenic ships — Very Large Ethane Carriers, or VLECs — to move the product to markets in Europe and Asia. Today, we begin a new series on the unique nature of overseas ethane exports, including why most incremental export volumes are tied to long-term supply deals with a handful of global ethylene plants designed — or reconfigured — to “crack” ethane.
Posts from Housley Carr
There’s no doubt about it: California’s decade-long efforts to expand the use of solar, wind, and other renewable energy and improve energy efficiency have enabled the state to significantly reduce its consumption of natural gas for power generation. But the Golden State’s rapid shift to a greener, lower-carbon electricity sector — and its push to shut down gas-fired power plants — has come at a cost, namely an increased risk of rolling blackouts, especially during extended heat waves in the West when neighboring states have less “surplus” electricity to send California’s way. The main problem is that while solar facilities provide a big share of the state’s midday power needs, there’s sometimes barely enough capacity from gas plants and other conventional generation sources to take up the slack when the sun sinks in the late afternoon and early evening. Today, we discuss recent developments on the power front in the most populous state, and what they mean for natural gas consumption there.
A combination of new-pipeline development, lower capex by producers, production shut-ins, and changing expectations for future production has significantly altered crude oil and natural gas market fundamentals in the all-important Permian Basin. Just over a year ago, Permian production was rising steadily and oil and gas pipelines out of West Texas were running at or near full capacity. Since then, nearly 2.2 MMb/d of incremental crude takeaway capacity has come online, and production dropped by about 700 Mb/d before rebounding somewhat in recent weeks. As for gas, some takeaway constraints remain, but they are limited to when pipelines are offline for maintenance, and will be alleviated when new pipelines start operating in 2021. Today, we discuss the recent downs and ups in Permian production, takeaway capacity additions, and the resulting impacts on markets and market participants.
The offshore Gulf of Mexico is often viewed as the rock-steady player in U.S. crude oil production. Unlike price-trigger-happy shale producers that quickly ratchet their activity up or down, depending on what WTI is selling for that month or quarter, producers in the Gulf base their big, upfront investments in new platforms or subsea tiebacks on very long-term oil-price expectations. Also, unlike shale wells, whose production peaks early then trails off, wells in the GOM typically maintain high levels of production for years and years. But don’t think for a minute that production in the Gulf can’t spike down, if there’s a good reason. GOM output dropped by 300 Mb/d, or 16%, from March to April as producers shut down wells in response to sharply lower oil prices, and a couple of weeks ago more than 80% of GOM wells were taken offline in anticipation of Hurricane Laura. Today, we look at offshore oil production ups and downs in a wild and woolly year and what’s ahead for the GOM.
Pipelines are lifelines to refineries, steam crackers, and other consumers of energy commodities, and even the hint that a major pipeline may be shut down raises big-time concerns. For evidence, look no further than Enbridge’s Line 5, which batches light crude oil and a propane/normal-butane mix across Michigan’s upper and lower peninsulas and to points beyond. One of Line 5’s two pipes under the Straits of Mackinac is temporarily out of service, halving the 540-Mb/d pipeline’s throughput, and Michigan’s attorney general continues to pursue a lawsuit that, if successful, could be Line 5’s death knell. Enbridge also is facing a fight on its plan to replace the twin underwater pipes with a new, safer “tunnel” alternative. All of which raises the question, what would be the market effects if Line 5 is permanently closed? Today, we conclude a miniseries on one of the Upper Midwest’s most important liquids pipelines.
Understanding whether propane production is up or down over the past few months is a bit more difficult than you might think, depending on which set of EIA numbers you choose to look at. The U.S. Energy Information Administration provides monthly numbers on the last day of the month lagged by about two months, and weekly numbers on Wednesdays, lagged by only five days. Both time series are closely watched by the propane market to assess the availability of supply for retail customers, petrochemical feedstock demand, and exports. Usually, these two sets of numbers move in tandem. But not always. The monthly numbers show production down by about 70 Mb/d from April to June, which is what you would expect given what was happening with crude and gas production at that point in time. Yet EIA weekly production numbers showed production increasing by about 90 Mb/d for the same period. So which way is propane production really trending? If you want to understand what’s going on, and you don’t mind delving into some deeply wonky NGL analytics, hang on for today’s blog.
Yet again, the Texas-Louisiana coast is bracing for a hurricane that has the potential to be really bad, not just for the people and homes in the storm’s path, but for the region’s all-important energy sector. Hurricane Laura will be crossing a swath of the Gulf of Mexico dotted with oil and gas production platforms, and is headed for an area chockablock with tank farms, refineries, and steam crackers, as well as export terminals of every stripe: crude oil, refined products, ethane, LPG, and LNG. There’s a good chance there’ll be a lot of disruption to many energy-related activities for at least the balance of this week — and maybe longer — but one of the biggest hits could come to Mont Belvieu, TX, the center of NGL storage and fractionation. Today, we discuss how the storm might affect not only storage at the U.S.’s largest NGL hub, but gas-processing activity hundreds of miles inland.
The Dakota Access Pipeline isn’t the only interstate liquids pipe facing an uncertain future. The fate of Enbridge’s Line 5, which batches either light crude oil or a propane/butanes mix from Superior, WI, through Michigan and into Ontario, also hangs in the balance as the company renews its battle with Michigan’s top elected officials to keep the 67-year-old pipeline open and its effort win regulatory approval to replace the pipe’s most important water crossing. Line 5 supporters say that closing the 540-Mb/d pipeline would slash supplies to residential and commercial propane consumers in the Great Lakes State, steam crackers in Ontario, and refineries and gasoline blenders in three states and two Canadian provinces. Critics of Line 5 counter that there are plenty of supply alternatives. Today we discuss the pipeline, what it transports, and who it serves, as well as challenges it faces.
The U.S. power sector’s shift to natural gas over the past few years has been a boon to gas producers across the Lower 48, especially in the Northeast. Scores of new gas-fired power plants have been built there during the Shale Era, and a number of coal-fired, oil-fired, and nuclear plants have been taken offline. New England is a case in point; gas-fired power now accounts for about half of the installed generating capacity in the six-state region (Connecticut, Rhode Island, Massachusetts, Vermont, New Hampshire, and Maine) — three times what it was 20 years ago. But New Englanders have a love-hate relationship with natural gas, and with renewables and energy storage on the rise, gas’s role in the land of the Red Sox, hard-to-understand accents, and lobsta’ rolls may well have peaked. Today, we discuss recent developments on the natural gas and power generation fronts in the northeastern corner of the U.S.
The collapse in crude oil prices this year hit U.S. producers hard, and forced them to make big cuts in their capital budgets and drilling plans. But it also helped to prove their resilience. Throughout the Shale Era, and especially since the 2014-15 oil price crash, producers have been increasing their productivity and slashing their production costs, enabling most of them to survive even when prices slipped below $30 and $20/bbl for a while. Not all producers are alike, however — neither is all production. Even with oil prices rebounding to about $40/bbl in recent weeks, production based on enhanced oil recovery (EOR) through carbon-dioxide (CO2) “flooding” has become economically challenged, at least for some producers. Can EOR, with its high production costs, survive in a low-price environment? Today, we take a fresh look at EOR in an era of $40/bbl crude.
The global effort to stop the spread of COVID-19 brought the commercial aviation sector to its knees, and slashed demand for jet fuel to its lowest level in 50 years. That, combined with lower demand for motor gasoline and — to a lesser extent — diesel, forced refineries in the U.S. and elsewhere to substantially reduce their crude oil input and to make major changes in their operations, all with the aim of bringing refined product supply and demand into closer balance. After a horrific spring, U.S. jet fuel production and demand have been rebounding somewhat in recent weeks, but getting back to pre-coronavirus levels may take a long time. Today, we review the flight from hell that the jet fuel market has suffered through so far this year, and how it is affecting refineries.
The COVID-19 pandemic has undone a number of long-standing energy-market expectations. Just a few months ago, U.S. crude oil production was hitting new heights, export volumes were rising fast, and producers, shippers, and others were worried whether there would be sufficient marine-terminal capacity in place. Now, crude production is down sharply, and while crude exports have held up during this year’s market turmoil, the old belief that exports would keep rising through the early 2020s is out the window. Where does that change in expectations leave all those crude export terminals along the Gulf Coast, many of which were recently built or expanded to help handle the flood of crude that was supposed to be heading their way? Today, we discuss highlights from RBN’s new Drill Down Report on crude-handling marine facilities along the Texas and Louisiana coast.
Since the mid-2010s, MPLX has been developing a far-reaching pipeline system for delivering heavier natural gas liquids and field condensate from the Utica and “wet” Marcellus plays to Midwest refineries for gasoline blending and refining, and to the Alberta oil sands for use as diluent. The multi-year, multi-project effort, which has involved the construction of new pipelines, the repurposing of existing pipes, and the development of new storage capacity, will reach another milestone next month, when MPLX starts batching normal butane and isobutane through most of the pipeline system. And further enhancements are on the horizon. Today, we provide an update on the master limited partnership’s long-running strategy for moving Marcellus/Utica-sourced liquids to market more efficiently and at a lower per-barrel cost.
For almost a year now, Corpus Christi-area marine terminals have been exporting more crude oil than their competitors in Houston, Beaumont, and Louisiana, largely thanks to the recent startup of new, large-diameter oil pipelines from the Permian to Corpus. Beginning today, with the expected arrival of the first tanker at the spanking-new South Texas Gateway Terminal in Ingleside, the Corpus area will have the potential to widen its lead in export volumes. In addition to its connections to the EPIC Crude and Gray Oak pipelines from West Texas — and the new Harvest Pipeline and the older Flint Hills Resources system — the South Texas Gateway facility can partially load 2-MMbbl Very Large Crude Carriers. Today, we discuss the Gulf Coast’s newest marine terminal and the important economic edge it gains from handling VLCCs.
For a few years now, U.S. natural gas producers have benefited from the electric-power sector’s shift from coal-fired plants toward gas-fired ones. The ongoing transition makes sense. Not only is gas-fired generation cleaner, it’s mostly been cheaper than the coal alternative. Better still, gas turbines and combined-cycle plants are very flexible companions to all those new wind farms and utility-scale solar facilities, whose variable output requires at-the-ready replacement power when the wind’s not blowing and the sun’s not shining. But with the continued push by many state regulators — and many utilities — for lower-carbon generation fleets, gas-fired plants are facing a growing challenge from energy storage, mostly in the form of very big lithium-ion batteries. Today, we look into the increasing use of large-scale batteries in utility settings and whether they might pose a serious threat to gas-fired power in the 2020s and beyond.