The Houston Ship Channel (HSC) is one of the busiest shipping lanes in the U.S. Each year, thousands of vessels utilize the waterway, importing and exporting goods ranging from pharmaceutical products to what the Census Bureau classifies as “Leather Art; Saddlery Etc.; Handbags Etc.; Gut Art”. More to the point of today’s blog: over 10 million tons of energy products move through the channel each month. But as ships grow ever larger, the ports and canals that service them must also adapt to be able to handle their increased dimensions. The Houston Ship Channel now finds itself in a situation where it must adapt to meet increasing market demands. Today, we continue our series on the issues facing some Texas ports and the measures being taken to help alleviate them.
In terms of raw tonnage, the Port of Houston is by far the busiest in the United States. The 52-mile-long Houston Ship Channel (HSC) — running from just outside downtown Houston out to an area between Galveston Island and Bolivar Peninsula — is the artery that enables the heavy ship traffic, much of it tied to crude oil, LPG, petroleum products and other hydrocarbons. But in the same way that Houston’s Interstate 45 traffic backs up during the morning commute, the ship channel traffic, which normally runs at about 60% of peak levels, can be (and has been) subject to delays when there’s an accident, visibility problems, or a slow-moving double-wide taking up two lanes. With energy-related export activity on the rise, efforts are underway to address those issues. Today, we begin a series on the issues facing some Texas ports and the measures being taken to help alleviate them.
The race is on and here comes WTI up the backstretch. On November 5, CME Group launched a Houston WTI futures contract, challenging a similar trading vehicle from Intercontinental Exchange (ICE) that started up in mid-October. Ever since crude flows to the Gulf Coast took off five years ago, the crude market has been clamoring for a trading vehicle that would accurately reflect pricing in the region that dominates U.S. demand from refineries, imports and exports. Now there are two. But their features are quite distinct. ICE’s contract reflects barrels delivered to Magellan East Houston, while CME’s contract is based on deliveries into Enterprise’s Houston system. The specs are different, as are the physical attributes of the two delivery points. Will both survive? Probably not. Futures markets tend to concentrate liquidity — trading activity — into a single vehicle that best meets the needs of the market. So, which of these will come out on top? That’s what the crude oil market wants to know. In today’s blog, we delve into the differences between the two new futures contracts for West Texas Intermediate (WTI) crude delivered to Houston and ponder the market implications of these new hedging and trading tools.
Today’s energy markets are being rocked by new technologies, massive flow shifts to exports, and a myriad of new midstream infrastructure projects — to say nothing of the continuing onslaught of Mother Nature. It is more important than ever to understand how the markets for crude oil, natural gas and NGLs are tied together, and that is why it is time again for RBN’s School of Energy. But … this is not the best time for our Houston conference venue. So we’ve made the decision to GO VIRTUAL! We will webcast the entire School in real-time, with the same content, the same faculty and the same models. And since an understanding of the new realities of today’s energy markets is so essential, we have renewed, restructured and rebuilt our curriculum to CONNECT THE DOTS across our content, data and models. That’s the theme for our upcoming School of Energy 2017 – Virtual Edition, which we summarize in today’s advertorial blog.
Last week Hurricane Harvey roiled the entire energy complex, with NGL markets suffering substantial disruption — curtailed natural gas liquids production from gas processing in the Eagle Ford and other basins, reduced operating rates at Mont Belvieu and other fractionation sites, shuttered LPG and ethane export docks, widespread refinery closures and a virtual shutdown of Gulf Coast petrochemical plants. While little major damage to facilities has been reported and several plants are now restarting, operating conditions continue to be extremely difficult for both the supply and demand sides of the market. Today we continue our look at how high winds and days of torrential rain affected the U.S. energy industry, this time focusing on NGLs.
It has been a tragic week for the Gulf Coast, with months if not years of cleanup and rebuilding ahead of the region. But already, Houston, Corpus Christi, Port Arthur/Beaumont, Lake Charles and other affected areas are coming back online through the hard work of resilient Texans and Louisianans as well as aid coming in from across the country. And even though the energy industry is also moving quickly to put Hurricane Harvey in the rearview mirror, the damage and disruption have been extensive. It is still much too early to fully understand what has happened and how long the recovery is going to take. But with information that we can piece together from public statements, data analysis and conversations with knowledgeable market participants, it is possible to start developing an assessment of Harvey’s effects. That’s what we will tackle in today’s blog.
Permian crude oil production and pipeline takeaway capacity out of the region are in a horse race —it’s a close one too, and the stakes are high. Twice in the past few years, Permian production growth has outpaced the midstream sector’s ability to transport crude to market, resulting in negative price differentials that cost many producers big-time. Now, thanks to increased drilling activity and producers’ heightened ability to wring more out of the play’s multistack formations, Permian production is expected to rise by at least another 1.5 million barrels/day (MMb/d) by 2022 —a 60%-plus gain over five years —raising the threat of another round of major price hits, maybe as soon as later this year. Today we continue a blog series on the challenges posed by rapid production gains in the hottest U.S. shale play.
The highly attractive production economics of the Permian’s multistacked, hydrocarbon-packed Delaware and Midland basins all but guarantee that the region’s output of crude oil, natural gas and natural gas liquids will continue rising—possibly at an even faster rate than what we’ve seen lately. That raises an all-important question: Will there be sufficient pipeline takeaway capacity in place to keep pace with all that growth? If there isn’t, some Permian producers will suffer from downward pressure on local prices—and that may cause them to have second thoughts about the big bucks they paid to gain access to the best Permian acreage in the first place. A production-growth forecast and a deep-dive assessment of existing and planned pipeline takeaway capacity are at the heart of RBN’s new Drill Down Report on the Permian. Today we provide highlights from the new report.
More than a dozen crude oil pipelines can deliver up to 3.4 million barrels/day (MMb/d) to the greater Houston area, with another 550 Mb/d of capacity planned, and as domestic production starts to grow again, a new round of projects is under way to build-out the region’s distribution pipelines, storage and marine-dock infrastructure. The developers of these Houston-area projects include a range of midstream players: from large, diversified midstreamers that own the long-distance pipelines flowing into the region to smaller players planning their first Houston projects. Today we conclude a two-part blog series on the latest round of projects and on the increasingly intense competition for barrels.
As U.S. crude production ramps back up and larger volumes flow to the Gulf Coast, competition is building among midstream companies for control over the final miles from pipeline to refinery or marine dock. Nowhere is this more evident than the Houston area, where more than a dozen pipelines can deliver as much as 4 million barrels/day to the region’s 10 refineries as well as to export docks. Owners of the long-distance incoming pipelines—seeking to secure terminal, storage and dock fees—are making significant midstream investment in Houston, but smaller players are also developing assets. Today we begin a two-part series describing the build-out and how competitive the market has become.
Waterborne crude volumes (including imports) delivered to coastal refineries in Texas, Louisiana and Mississippi by domestic producers peaked at 27% of inputs in 2014 as regional plants processed increasing quantities of shale crude. Since then, these volumes have plummeted to 15% of inputs in March 2016 as Gulf Coast refiners have returned to more competitive imports instead. At the same time Eagle Ford crude volumes shipped along the Gulf Coast have fallen 28% this year in response to declining production and narrow price differentials between Texas and Louisiana ports. Gulf Eagle Ford crude now also plays a far smaller part in export markets than WTI grades. Overall exports have not increased since the end of the export ban but volumes to Canada have plummeted as shipments to other nations have increased. Today we review the shifts in waterborne flows across the Gulf Coast region.
While recent analysis has raised concerns crude oil pipelines are running half empty the opposite is true for many of the nations’ refined product distribution pipes. Take the huge Colonial Pipeline system that delivers as much as 2.7 MMb/d of refined products from Gulf Coast refineries to destinations up the East Coast as far as New York. The southern stretch of the pipeline from Pasadena near Houston to Greensboro, NC has been running full since 2012 - meaning that shipper volumes are subject to rationing or apportionment. Today we start a two-part series explaining why the Colonial pipeline is so congested and how it operates.
Over the past few years, midstream companies have responded to the boom in crude oil and lease condensate production in the Eagle Ford and the Permian by developing significant new pipeline capacity to, as well as storage and dock facilities in, both Houston and Corpus Christi. Now, with production in the Eagle Ford off its high and growth in the Permian slowing, these same midstreamers (and producers, marketers, refiners, and exporters of condensate and other refined products) are taking stock, and assessing not only what new infrastructure might still be needed in this period of lowered expectation, but whether shifting more of their attention (and liquids) towards Corpus instead of Houston might be warranted. Today, we continue our look at Corpus Christi’s increasing role as a crude/condensate powerhouse.
Over the past couple of years, Corpus Christi has emerged as an attractive refining and distribution hub for Eagle Ford and more recently Permian Basin crude oil and lease condensate. Despite Corpus’s promise, however, currently low commodity prices have made key players skittish about making long-term—and potentially costly—commitments to additional Permian-to-Corpus pipeline capacity, and to crude refining, condensate splitting and marine dock infrastructure investments in or near Corpus. Today, we begin a deep-dive into Corpus Christi-area crude- and condensate-related infrastructure and Corpus’s potential as an even bigger destination for Eagle Ford and Permian output.
Permian Basin crude production more than doubled since 2011 to reach nearly 2 MMb/d today, but that rate of increase has leveled off since prices crashed last year. Meantime 750Mb/d of long-haul pipeline takeaway capacity came online in the first half of 2015 - greatly exceeding today’s take-away requirements. And there is more to come next year when the 470 Mb/d Enterprise Midland-to-Sealy pipeline is expected online – leading to fears regional pipeline infrastructure is overbuilt. How about inside the Permian Basin? Today we start a series reviewing Permian gathering system build out.