The NGL storage and fractionation hub at Mont Belvieu, TX, grabs all the attention, but more than 1 MMb/d of fractionation capacity — nearly one-third of Texas’s total — is located elsewhere in the Lone Star State. And with NGL production and demand for fractionation services soaring in the Permian, SCOOP/STACK and other nearby plays, the market will need all the fractionation capacity it can find. We’ve heard that there’s little, if any, gap between what the existing fractionators in Mont Belvieu can handle and what they’re being asked to process. That’s music to the ears of fractionation-plant owners elsewhere in Texas — assuming they aren’t already at capacity themselves, they might be able to pick up some overflow business from Mont Belvieu. Today, we continue our review of fractionators and other key NGL-related infrastructure along the Gulf Coast.
Posts from Housley Carr
Mexican demand for U.S.-sourced refined products continues to increase, but Mexico lacks the infrastructure required to efficiently import, store and distribute large volumes of gasoline and diesel. That has spurred the rapid build-out of new port and rail terminals, new pipelines and new storage capacity on both sides of the U.S.-Mexico border. At the same time, Mexico’s state-owned energy companies are gradually opening access to their existing refined-products pipeline and storage networks — which helps a little, but not enough. Today, we discuss the latest round of midstream projects tied to U.S. exports of motor and jet fuels to its southern neighbor.
Mont Belvieu may be the epicenter of NGL storage, fractionation and distribution along the Gulf Coast, but the rest of Texas offers almost half as much fractionation capacity — about 1 MMb/d of it — and a good bit of storage and pipeline connectivity too. These are particularly important facts in the summer of 2018, when demand for fractionation services in Mont Belvieu is at or near an all-time high and increasing volumes of NGLs are headed toward the hub. So what else has the Lone Star State got on the fractionation and NGL storage front? And are these assets experiencing the same strong demand as their counterparts in Mont Belvieu? Today, we continue our review of fractionators and key NGL-related infrastructure.
The slower-than-hoped-for build-out of natural gas pipelines and gas-fired power plants in Mexico has been a source of frustration for producers in the Permian Basin, who face pipeline takeaway constraints to their west, north and east and who desperately want to send more gas south. But it’s not just the Permian that benefits as the doors to the Mexican market creak open. The Eagle Ford — the Permian’s less glamorous step-sister — was the primary source of the first wave of gas exports to points south of the border. Now, with the recent opening of the Nueva Era Pipeline from the Rio Grande to power plants and other customers in Monterrey and Escobedo, another Mexican demand outlet will be made available to South Texas producers. Today, we discuss Howard Energy Partners and Grupo CLISA’s newly completed pipeline and the boost it gives to Eagle Ford production.
The planned implementation of the International Maritime Organization’s rule slashing allowable sulfur-dioxide emissions from ocean-going ships on January 1, 2020, would create significant demand for 0.5%-sulfur marine fuel — a refined product that few refiners produce today. That could present a big challenge to the global refining sector, which will be called upon to produce marine fuel that complies with “IMO 2020,” as the rule is commonly known. But refiners have stepped up before, and if the IMO 2020 mandate proves to be unachievable and would put global commerce at risk, there could be ways to deal with it — including exemptions or implementation delays. In any case, the move toward much cleaner bunker fuel will be a boon to complex refineries along the U.S. Gulf Coast and elsewhere that can break down bottom-of-the-barrel “residual” fuel oil into feedstocks for gasoline, diesel and other high-value products. Today, we continue our analysis of IMO 2020 and its effects.
For the first time ever, U.S. crude oil exports have hit the 3 MMb/d mark — a once-unthinkable pace equivalent to sending out 10 fully loaded Very Large Crude Carriers a week. VLCCs, with their 2-MMbbl capacity and rock-bottom per-bbl delivery costs, are the most cost-effective way to transport crude to distant markets like China and India. But there’s still only one terminal on the Gulf Coast that can fill a VLCC to the brim — the Louisiana Offshore Oil Port — and pipeline connections from key Texas and Oklahoma plays to LOOP are limited. Elsewhere along the coast, VLCCs need to be loaded in offshore deep water by reverse lightering from smaller vessels — a slower and more costly loading process. Change is a-comin’, though. Companies are testing the docking and partial loading of VLCCs at terminals along the Texas coast, and plans for a number of greenfield facilities capable of partially — or even fully — loading the gargantuan vessels at the dock are being considered. Today, we review the latest efforts to streamline the loading of VLCCs and what they mean for crude-export economics.
For a while, the 840 Mb/d of NGL fractionation capacity that was added in Mont Belvieu, TX, between 2013 and 2016 — combined with the 1.2 MMb/d of capacity already in place before that four-year fractionator construction boom — was more than enough. But the run-up in NGL production in the Permian, SCOOP/STACK and other liquids-rich plays in 2017 and the first half of 2018 is quickly increasing the demand for fractionation services and challenging Mont Belvieu’s ability to keep up. Now, another 465 Mb/d of fractionator capacity is under development. Will they be finished soon enough? Will still more be needed? Today, we continue our review of fractionators, NGL and purity-product storage and other key infrastructure, this time with a look at ONEOK and Gulf Coast Fractionators’ assets.
The weeks-long shutdown at Syncrude Canada’s oil sands production facility in northeastern Alberta will alleviate pipeline takeaway constraints that have significantly widened the price spread between Western Canadian Select (WCS) and West Texas Intermediate (WTI) crude oil. But when Syncrude returns later this summer, there’s every reason to believe that the constraints will too, as will the need for significantly more crude-by-rail shipments. Railed volumes out of Western Canada have been increasing in recent months, but not by enough to avert WCS-WTI differential blowouts to $25 and even $30/bbl. The catch is that most of the rail-terminal capacity built a few years ago is mothballed, and that railroads are reluctant to dedicate more locomotives and personnel unless shippers make one-, two- or even three-year commitments to take-or-pay for that logistical support. Today, we consider the ongoing challenges Western Canadian producers face in moving their crude to market.
The NGL storage and fractionation complex in Mont Belvieu, TX, now offers 2.1 MMb/d of fractionation capacity — the largest concentration of fractionators in the world. As impressive as that may be, though, NGL production growth in the Permian Basin, the SCOOP/STACK and other liquids-rich plays is quickly ramping up the demand for fractionation services and challenging Mont Belvieu’s ability to keep up. A number of new fractionators are being added, but will they come online soon enough? Today, we continue our review of fractionators, NGL and purity-product storage and other key infrastructure within and near the NGL Capital of the World.
Permian natural gas production increased by about 10% in the winter of 2017-18, from about 7.1 Bcf/d to 7.8 Bcf/d, but all spring it’s remained relatively flat, never averaging more than an even 8 Bcf/d. There’s good reason for that. While at first glance it might seem as if there’s enough pipeline takeaway capacity out of the Permian to accommodate considerably more production growth, the big pipes from the Waha Hub to Mexico are transporting far less than they’re capable of because of delays in developing new pipes and gas-fired power plants on the Mexican side of the border. And pipes from the Permian to California are running less than full, in part because of that state’s hard tilt to renewable power. That’s left the Permian with a takeaway conundrum that may not be fully solvable — at least for a time — until new, greenfield pipeline capacity from West Texas to the Gulf Coast comes online in 15 to 18 months. Today, we discuss the options that producers, gas processors and midstream companies may need to consider if things get really tight.
The fractionation and NGL storage complex in Mont Belvieu, TX, would surely qualify as one of the Seven Wonders of the Energy World, if there were such a list. With more than 250 million barrels of NGL storage carved — by water! — out of an enormous subterranean salt dome formation, and nearly two dozen fractionation plants with a combined capacity of more than 2 MMb/d, Mont Belvieu not only serves as the largest receipt point for mixed NGL streams on the planet, it is also the key hub of distribution for the ethane, propane, normal butane and other NGL purity products that are either consumed by Gulf Coast steam crackers and refineries or exported to foreign end-users. But unlike wonders of the ancient world like the Great Pyramids at Giza, Mont Belvieu is still very much a work in progress, with new storage caverns and new fractionators now under development to try to keep up with the breakneck pace of U.S. NGL production growth. Today, we begin a company-by-company review of fractionation capacity and other key infrastructure there.
Natural gas producers in Western Canada, with their share of U.S. and Eastern Canadian markets threatened by competition from producers in the Marcellus/Utica and other shale plays south of the international border, for years have seen prospective LNG exports to Asian markets as a panacea. But efforts to develop liquefaction “trains” and export terminals in British Columbia failed to advance earlier this decade — for starters, their economics weren’t nearly as favorable as those for U.S. projects like Sabine Pass LNG. Then, by 2016-17, global markets were awash in LNG as new Australian and U.S. liquefaction trains came online, and the BC LNG projects still alive were either delayed further or scrapped. Now, with LNG demand on the upswing and the need for additional LNG capacity in the early-to-mid 2020s apparent, the co-developers of LNG Canada — Shell, PetroChina, Korea Gas and Mitsubishi — have attracted a new and significant investor: Petronas, Malaysia’s state-owned oil and gas company and owner of Progress Energy Canada, which has vast gas reserves in Western Canada. Today, we continue our review of efforts to send natural gas and crude oil to Asian markets with a fresh look at the LNG project and TransCanada’s planned Coastal GasLink pipeline, which will deliver gas to it.
The NGL sector is firing on all cylinders. Natural gas liquids production in the Permian, the SCOOP/STACK and other key basins is up, up, up. A number of new, ethane-consuming steam crackers are coming online along the Texas and Louisiana coast, most conveniently close to the NGL storage and fractionation hub in Mont Belvieu, TX. The export market for liquefied petroleum gases — propane and normal butane — is through the roof, averaging more than 1 MMb/d in the first five months of 2018 (almost all of it being shipped out of Gulf Coast ports), and ethane exports are strong too. What’s not to like? Well, NGLs don’t do anyone much good until they are fractionated into “purity products” like ethane, propane, normal butane etc., and the rapid run-up in U.S. NGL production — combined with the reluctance of producers to commit to new fractionation capacity — has the existing fractionation plants in Mont Belvieu running flat-out to keep up. Today, we begin a review of the NGL Capital of the Western World and considers why Mont Belvieu — as big as it is — is getting bigger.
Western Canada is blessed with extraordinary hydrocarbon resources and in recent years has been ramping up production in the Alberta oil sands and in the Duvernay and Montney shale plays. The U.S. is pretty much Canada’s only crude oil and natural gas customer, though, and there are limits to how much Canada can export to its southern neighbor — especially in the Shale Era, with the U.S. producing more oil and gas than ever and meeting an increasing share of its own needs. So Canadian producers, midstream companies and others have been working to gain access to new, overseas markets. It has not gone well. Pipeline projects to transport oil and gas to the British Columbia coast have been set back time and again, as have plans for crude and LNG export terminals. At last, there may be some good news. The Canadian government has stepped in to help push through a critically important oil pipeline to the coast, and BC’s leading LNG project just signed on a major new investor/customer. Today, we consider recent moves that could finally allow large volumes of Western Canadian oil and gas to be shipped to Asia.
Drilling and completion activity in the Permian Basin doesn’t only produce vast quantities of energy, it consumes a lot of energy too, mostly in the form of diesel fuel to power the trucks, drilling rigs, fracturing pumps, compressors and other equipment needed to keep the oil patch humming. And while refineries within or near the Permian meet a portion of the region’s needs, rising demand for diesel there is spurring the development of new infrastructure — and the repurposing of existing assets — to bring additional fuel into the Permian from refineries along the Gulf Coast. Today, we discuss efforts to move more diesel to the oil fields of West Texas.