Since mid-July — only a few weeks ago — four proposals have been unveiled to build offshore crude export terminals along the Gulf Coast that would be capable of fully loading Very Large Crude Carriers. That’s an extraordinary burst of interest in new infrastructure development, and a signal that (1) more export growth is on the horizon and (2) VLCCs will play a much bigger role in transporting that crude. A leading contender in the race to construct new offshore terminals is Trafigura, the Swiss-based logistics and physical-trading giant, which in recent years has become a major player in U.S. energy markets. Today, we continue our review of made-for-VLCCs offshore terminals with a look at Trafi’s plan.
Crude oil inventories at Cushing have been in a free fall. After last peaking at more than 69 MMbbl in April 2017, stockpiles have decreased to less than 22 MMbbl recently, nearing all-time lows for tank utilization at the Oklahoma crude-trading hub. While we’ve seen volumes drop quickly in the past, inventories have now declined for 12 straight weeks at a staggering pace. Traders, refiners, and other market participants are starting to fret. Is this just another cyclical trend or are market factors exacerbating the impact? Today, we examine the influence of historical pricing trends on Cushing inventories and why it seems that demand factors are speeding up the drop.
On Thursday, August 9, a U.S. District Court judge approved a request by a Canadian mining company to seize shares of a subsidiary of Petróleos de Venezuela SA (PDVSA) that controls CITGO Petroleum Corp. The ruling was made to satisfy a $1.2 billion arbitration award against the Venezuelan government. While details of the full ruling are yet to be released, this decision could have an enormous knock-on effect on the various other parties seeking payment from the struggling oil company for asset seizures and unpaid debts. Today, we review the assets of CITGO Petroleum Corp., the U.S. arm of PDVSA.
Much like their heated competition to build new crude oil pipelines from the Permian to the Gulf Coast, midstream, logistics and trading companies are jockeying to construct the first new export terminal capable of fully loading Very Large Crude Carriers — Trafigura joined the fray earlier this week. While VLCCs are by far the most cost-efficient way to haul crude to Asia, their Godzilla-like physical dimensions restrict the number of land-based terminals they can use. And even those that can accommodate these seagoing behemoths can only load a VLCC part-way — “reverse lightering” out in deeper, open waters is required to fill the supertanker to the tippy top. So a handful of ambitious midstreamers are developing plans for offshore terminals out in deep water, miles from the Texas coast. Today, we continue our review of these proposals with a look at JupiterMLP’s plan for a terminal off Brownsville — and a new Permian pipeline to the city.
Rising crude oil production in Western Canada, filled-to-the-brim pipelines out of the region, and yet another blowout in the price spread between Western Canadian Select (WCS) and West Texas Intermediate (WTI) are combining to spur a genuine revival in crude-by-rail (CBR) shipments from Canada to the U.S. CBR has helped out Western Canadian producers before, moving increasing volumes south through 2011-14 until new pipeline capacity came online. But this time, the number of barrels being moved out of Western Canada by rail is already moving into record territory, and — with the addition of incremental pipeline capacity still at least a year away, and maybe more — railed volumes are likely to continue rising in the months to come. Today, we discuss recent developments and what producers, shippers and railroads see coming in the months ahead.
There has never been anything like the 2018 Permian Basin. In just five years, oil production has tripled, gas production has doubled and NGL output is up about 2.5 times. Crude oil pipelines out of the Permian are filled to the brim and the differentials between crude in Midland and both the Gulf Coast and Cushing have blown out. It is the same for natural gas, with pipe capacity nearly maxed out and basis wide. So far, most Permian NGLs have avoided a similar traffic jam in the local market, only to run into constraints downstream. But the overall Permian market is headed for a breakout! Massive infrastructure development is coming to the basin and the takeaway capacity constraints will be history — at least for a while. What will this mean for the Permian market, and for that matter, for markets across North America and the globe? Clearly, we need to get the major players together under one roof and figure it out. And that’s just the plan for PermiCon 2018. Our goal for this unique conference is to bridge the gap between fundamentals analysis and boots-on-the-ground market intelligence. Warning! Today’s blog is an unabashed advertorial for our upcoming conference.
As Gulf Coast marine terminal owners consider ways to at least partially load Very Large Crude Carriers (VLCCs) at their facilities, a handful of midstream companies also are planning offshore terminals in deep water that would allow the full loading of VLCCs via pipeline. Projects under development by Oiltanking and others for sites along the Texas coast would appear to have at least two legs up on the Louisiana Offshore Oil Port, or LOOP. For one, they’d have more direct access to the Permian, Eagle Ford and other crudes flowing to coastal Texas. For another, the new terminals would be focused on crude exports — no double-duty for them. Today, we begin a review of the projects vying to be the first LOOP-like project in the deep waters off the Lone Star State.
U.S. crude oil production has doubled in the past eight years, from 5.5 MMb/d in 2010 to a record 11.0 MMb/d this month — an astonishing 9% compound annual growth rate. But there’s more to the Shale Revolution than higher production. Its most noteworthy characteristic may be a newfound market responsiveness that U.S. production volumes have to price, in which U.S. producers flex their “sweet spots” and an at-the-ready inventory of drilled-but-uncompleted wells (DUCs) that can be ramped up when prices warrant and pulled back when they don’t. This newfound flexibility has profoundly changed the role of the U.S. in global markets. In today’s blog, we take a big-picture look at crude oil production growth, the special ability of U.S. producers to respond to shifts in crude pricing, and the potential for the U.S. to have a stabilizing role in global markets.
Since early this year, the Midland crude differential has continued to widen, trading one day last week at a discount of $15.75/bbl to West Texas Intermediate (WTI) at Cushing, the widest spread since August 2014 before settling back to $11.25/bbl on Monday. The wide price differential is a result of fast-growing production in the Permian and bottlenecked takeaway pipelines. But the trajectory of this increasing price spread has been anything but smooth. Lately, we have seen a blip in the price differentials right around the 19th or 20th of the month. In each of the last three months, for a short-lived 24 to 48 hours, the Midland-Cushing price differential has narrowed by $2/bbl or more as Permian shippers have gone on feeding frenzies. Today, we look at these brief upticks in pricing and the pipeline and trader mechanics behind them.
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.
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.
Crude oil pipelines out of Cushing are filling up. With U.S. crude production approaching the 11 MMb/d mark, more and more production from the Rockies, Midcontinent and Permian is funneling into the Cushing, OK, trading hub. It’s getting increasingly difficult to get all of that volume to the major demand center at the Gulf Coast. The two major pipelines out of Cushing — Seaway and Marketlink — are near full capacity and differentials are responding as West Texas Intermediate (WTI) at Cushing is now trading at a $7.60/bbl discount to Magellan East Houston (MEH) at the Gulf. Today, we look at some of the major factors affecting the WTI-MEH spread, space on major pipelines between the two points, and potential implications going forward.
The Permian Basin is awash in light, sweet crude oil that’s cheap to produce and easy to process. It’s so awash, in fact, that supplies are overwhelming takeaway pipeline capacity. The resulting bottleneck in West Texas has cratered prices in Midland, where West Texas Intermediate (WTI) — the region’s light, sweet benchmark — has blown out price-wise against the same grade in other locations, including Houston, with its crude-export docks. Less well known, but influential beyond its geography, is Midland West Texas Sour, or WTS. WTS is suffering from the same wide differentials as WTI at Midland, and those yawning spreads are dragging down the price of Maya, Pemex’s flagship heavy, sour crude. Today, we discuss some surprising ripple effects of takeaway constraints out of the Permian.
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.
Crude oil pipelines out of the Permian are filled to capacity and the differentials between crude in Midland and in Cushing and Gulf Coast destination markets are wide and likely to widen. That has spurred Permian producers and shippers to consider every possible option for moving incremental barrels out of the play, including two old short-term standbys: tanker trucks and crude-by-rail. Cost isn’t a major issue — the price spread and the Permian’s low break-evens will probably justify the higher expenses associated with trucking and railing crude. But that doesn’t mean that badly needed truck and rail capacity can appear with a poof as if by magic. No, even wads of cash may not be enough to quickly round up the hundreds — thousands? — of trucks and drivers that would be required to make a significant dent in the Permian’s takeaway shortfall. And developing brand new crude-by-rail terminals can take a year or more — too much time to address the play’s more immediate needs. Today, we continue our look at the frenzied efforts under way to move more Permian crude to market.