There are common drivers behind the handful of offshore crude oil terminals now under development along the Gulf Coast, chief among them the well-founded belief that shippers would prefer putting crude on Very Large Crude Carriers (VLCCs), which can only be fully loaded in deep water. But each of these projects also has unique nuances — its own specific rationale and characteristics. Tallgrass Energy’s plan is a case in point in that it involves a new pipeline from the crude hub in Cushing, OK, to the refinery center in St. James, LA, and to a new onshore crude storage and loading terminal a few miles down the Mississippi River, to be followed by a VLCC-ready offshore terminal capable of both exporting and importing crude. Today, we continue our review of made-for-VLCCs offshore terminals with a look at Tallgrass’s effort to deliver neat, unblended barrels directly from multiple inland plays to deep water — “shale-to-ship,” in other words.
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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.
There was a time when natural gas prices in the Permian Basin spent most of the summer bouncing within a few cents of the benchmark Henry Hub, as ample pipeline takeaway capacity and seasonally strong demand combined to keep a lid on price blowouts. Times have certainly changed, with ballooning local production overwhelming existing takeaway capacity and widening the price spread between Permian gas markets and Henry Hub. However, the erosion in Permian gas basis has been anything but orderly. The current market is defined by significant swings in gas basis, depending on factors such as pipeline maintenance and weather. So, while the trend in Permian gas basis is decidedly lower, the path to get there is looking like a gut-wrenching roller coaster ride. Today, we look at recent swings in Permian natural gas basis pricing.
This spring, TransCanada launched service for its 230-MMcf/d Sundre Crossover expansion, increasing transportation capacity for moving Alberta natural gas production to the U.S. Pacific Northwest. That may seem like a trifling volume in the big scheme of the North American gas market. But considering that Canadian and U.S. producers already are locked in a heated battle for market share of U.S. demand and pipeline capacity, it’s enough for Canadian supply to gain ground. Since the Sundre in-service date, deliveries to the Kingsgate point at the British Columbia-Idaho border have ratcheted up to the highest levels in at least a decade. As a result, Canadian exports have managed to elbow out Rockies gas from the California market, and set off a ripple effect that’s pushing more gas east to the Midcontinent. Today, we examine the shifting gas flows in the West.
For 10 years prior to 2018, the differential between propane prices at the Conway, KS, hub averaged less than a nickel per gallon below Mont Belvieu. In fact, between 2013 and 2017, the price spread was only 3.5 c/gal — excluding a winter 2014 Polar Vortex aberration — which basically reflects the cost of moving barrels 700 miles north-to-south. Not this year, though. After starting 2018 at 3 c/gal, the propane price spread took off, and has averaged 18 c/gal since April, some days moving above 26 c/gal, far above the per-bbl cost of transporting propane 700 miles south to Mont Belvieu. Is it pipeline capacity constraints? In part. But there is a much more significant factor driving this differential wider, not only in the propane market, but across all five of the NGL purity products. What is this mysterious factor? To find out, read on. But here’s your first clue: the problem is not in Kansas anymore.
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.
Crude oil and natural gas production in the Bakken are at record highs, and with the surge in production has come infrastructure constraints and higher rates of flared gas, renewing concerns about possible production shut-ins. As gas production volumes exceeded gas processing capacity, the flaring rate in April 2018 rose to 15% of total monthly volumes –– precisely the current limit set by North Dakota’s gas capture plan and three percentage points above the 12% cap due to kick in this November. Rig counts, producers’ drilling plans and $70/bbl crude oil prices all point to further production growth, which means that without additional processing capacity — or a change in the gas-capture policy — it will be increasingly difficult for producers and processors to comply. Today, we look at the latest developments in Bakken gas production, gas-related infrastructure and the gas capture policy.
Permian natural gas fundamentals were rocked with some major infrastructure news on Monday, when Kinder Morgan announced its plans to build the 2-Bcf/d Permian Highway Pipeline (PHP) from Waha to the Texas Gulf Coast. The announcement revealed that EagleClaw Midstream, a Blackstone Energy Partners portfolio company, has signed a letter of intent to become a 50% owner in the project and commit natural gas volumes to the pipeline. Adding firepower to the project, Apache Corp. is committing significant volumes to the pipeline too, with an option to take an ownership stake. While Kinder Morgan and EagleClaw Midstream stopped short of a final investment decision (FID), the destination flexibility that PHP’s tie-ins with other key pipes offer makes the project a major contender in the race to become the second new long-haul natural gas pipeline out of the Permian. Today, we discuss the latest infrastructure development in the Permian natural gas market.
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.
As U.S. LNG exports play an increasing role in the global market, the U.S. will not only be exporting its vast natural gas supplies but also to a degree its market realities — namely, the risks, opportunities and, at times, volatility of a highly liquid, fungible and economically-driven spot market. The global LNG market also has shifted toward more flexible and spot-oriented trade, opening the window for some ad lib wheeling and dealing based on the prevailing economic conditions at any given time. These two factors together will come with significant implications across the supply chain — from the producing basins to the pipeline transport routes and from the export terminals to the destination markets they are serving. This month, with feedgas receipts at Sabine Pass LNG down and an explosion on a key supply route from Appalachia to Louisiana, we are starting to see how this integration of the U.S. and global markets is likely to play out. To help you keep up with this complicated dynamic and extrapolate the big-picture impacts, today we introduce RBN’s new LNG Voyager Report, featuring a comprehensive, pipe-to-port-to-destination approach to understanding how U.S. LNG fits into the global market.
There has been a lot of acrimony and polarization among the natural gas industry, the environmental community, various consumer advocates, industrial energy users, organized power markets and renewables developers in recent years. However, the ongoing government efforts to prop up the power sector’s coal-fired and nuclear generators have succeeded in uniting all those disparate interests into a single voice saying a single word: No! Today, we discuss the history of the administration’s planned support of coal and nuclear, the unusually unified reaction to it from groups that are more often at odds with each other, and some underlying assumptions about natural gas that aren’t — well — how the gas industry says it works.
An influx of natural gas supply in northern Louisiana — from Marcellus/Utica inflows and the rebound in Haynesville Shale production — is not only reversing long-held flow patterns but is also starting to fill up existing pipeline capacity on routes to the Southeast U.S. and the Louisiana Gulf Coast, where demand is growing. As more LNG export capacity comes online in the Bayou State, more gas will be needed at the coast, and, with existing routes to the coast filling up, more pipeline capacity will be needed as well. These factors are expected to transform the Louisiana gas market over the next several years, with impacts to prices, transportation values and basis, and with repercussions for both the U.S. gas market and global LNG trade. Today, we discuss highlights from our new Drill Down Report on the fast-changing Louisiana gas flow patterns and the need for more pipeline capacity.
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.
Permian producers led the U.S. exploration and production (E&P) sector’s remarkable recovery from the financial crisis that was spurred by the oil price crash in late 2014. Dramatically lower costs and higher well productivity led to strong margins even at $50/bbl oil and promised bountiful returns should oil prices move higher. It’s no surprise that investors flocked to the stocks of Permian-focused producers, driving equity valuations, as measured by enterprise value per barrel of oil equivalent (boe) of proved reserves, to multiples three or four times the industry average. Recently, however, there have been growing investor concerns that logistical constraints on shipping crude oil and gas out of the region could restrict cash flows, investment budgets and output growth, and on Friday, Baker Hughes reported that the Permian’s rig count was down (albeit by only four, to 476). Since May 15, stock prices of smaller pure-play Permian producers Concho Resources, Diamondback Energy, Parsley Energy, RSP Permian, and Laredo Petroleum have fallen 10-15%. One of the larger Permian producers has bucked the trend, though: Pioneer Natural Resources. Today, we explore the drivers of Pioneer’s current valuation and analyze the factors that could propel future growth.