Since 2012, the capacity of the Jones Act fleet of tankers and large articulated tug barges (ATBs) has increased by more than one-third, to 22.5 million barrels, and over the next 18 months, new-build tankers and more large ATBs will add another 4.5 million barrel –– or 20% –– to the capacity total. That’s raised a lot of concern among vessel owners about a capacity glut and the potential for bargain-basement charter rates. What’s important to factor in, though, is that a lot of older Jones Act vessels are getting close to retirement age, and their exit from the shipping “work force” will help to mitigate the effects of any over-build. Today, we continue our series on recent developments in the Jones Act fleet and how they affect crude oil and petroleum products shippers.
Daily Energy Blog
With crude storage tanks along the U.S Gulf Coast nearly full, the nine storage terminals currently operational in the Caribbean offer an advantageous close-by alternative. Right now these terminals are heavily used by Venezuela for oil blending and distribution, but there has been growing interest and investment from outside the region. China is now neck and neck with the U.S. as the world’s largest crude importer and is making a significant strategic investment in Caribbean storage to cement crude supply deals with Latin American producers. Private equity fund ArcLight Capital and trader Freepoint Commodities together purchased a huge terminal and shuttered refinery in the U.S. Virgin Islands in January of this year (2016) and have leased most of the working storage to Chinese-owned Sinopec. Today, we examine the growing role of Caribbean crude terminals. (This blog is based on Morningstar’s recently published Caribbean Crude Storage Outlook [1], which provides a comprehensive analysis of this evolving market.)
Despite slowdowns in drilling, completions and crude oil production in the Niobrara Shale region in northeastern Colorado and eastern Wyoming, new pipeline takeaway capacity out of the tight oil play is being built, apparently due to the expectations of some that the Niobrara will bounce back more quickly than most other basins if and when crude prices rise –– and stay –– above $55-60/bbl. Later this year, the 340 Mb/d Saddlehorn/Grand Mesa Pipeline to the crude storage and distribution hub in Cushing, OK is expected to begin operation, supplementing Pony Express and White Cliffs, which already move crude from the Bakken and the Niobrara’s Denver-Julesburg and Powder River basins, and giving Niobrara producers more than enough takeaway capacity for the foreseeable future. Today, we look at the possibility of an infrastructure over-build in the eastern Rockies.
The famous Field of Dreams misquote “If you build it, they will come” certainly has proved true for the midstream companies that added a record 18.7 MMbbl of crude oil storage capacity in PADD 2 in late 2015 and early 2016. During that six-month period, crude inventories in PADD 2 blasted 24.4 MMbbl higher to a record 155.6 MMbbl. And while PADD 2 oil stockpiles have been shrinking somewhat in recent weeks, they remain above 150 MMbbl—a mark the PADD had never seen before this year. Storage levels have been particularly high at the Cushing, OK storage and distribution hub within PADD 2. Why is so much crude being socked away? Today, we continue our look at the new storage capacity being added in the U.S., and at why demand for storage has been so high.
Tallgrass Energy Partners’ Pony Express Pipeline provides capacity to move 230 Mb/d of Bakken crude oil received at Guernsey, WY all the way to the mega-hub at Cushing, OK, making it one of the most important pipeline corridors out of the Williston Basin. Possibly because of its moniker ‘Express’, it is often thought of as a bullet line, hauling barrels 760 miles in a straight shot across Wyoming, Colorado, Nebraska, Kansas and into Oklahoma.
More new crude oil storage capacity came online in the U.S. in the fourth quarter of 2015 and the first quarter of 2016 than in any half-year period in memory, and still more capacity is being planned. Even with all this new capacity—and the slowdown in crude oil production—the storage utilization rates at Midwest/Mid-continent and Gulf Coast tank farms, underground salt caverns and refineries are at or near record highs too. And tens of millions more barrels of storage capacity are on the drawing boards in anticipation of further incremental needs. But the energy sector is pulling back, right? What gives? Today, we begin an update on crude storage trends and crude storage facilities in Petroleum Administration for Defense Districts (PADDs) 2 and 3, which together account for 82% of U.S. crude storage capacity.
A big build-out of Jones Act product tankers and large ocean-going barges is well under way, just as the future demand for these vessels is coming into question. Within the next 18 months, a total of 17 Jones Act product tankers and large ocean-going articulated tug barges (ATBs) with a combined capacity of more than 4.5 million barrels (MMbbl) will be delivered, boosting the total fleet capacity of these types of vessels by 20%. These new-vessel orders were made a few years ago in response to increased shipments of crude oil within the U.S. that, at the time, had resulted in a shortage of Jones Act product tankers and large ATBs. This in turn led to higher charter rates and the resulting increased costs of shipping crude oil and petroleum products in the coastwise trade. Now though, the decline in U.S. crude oil production has upended expectations. Today, we begin a series on the impact of hydrocarbon market changes on the Jones Act fleet.
For the past five years, crude oil producers in the Bakken have depended on railroads to transport a significant share of their output to market—there simply hasn’t been enough pipeline capacity out of the tight-oil play. Now, construction of the long-awaited, 450 Mb/d Dakota Access Pipeline (DAPL) is finally poised to begin, and a late-2016 online date for DAPL is planned. DAPL’s capacity would enable producers to further reduce their use of crude-by-rail, but with Bakken production on the decline, will DAPL really be needed? And what about additional out-of-the-Bakken takeaway capacity being planned? Today, we consider the challenges and pitfalls of developing midstream infrastructure in fast-changing markets, focusing on Bakken crude.
The STACK shale play west/northwest of Oklahoma City has quickly emerged as one of the hottest hot spots, and two “sweet-spot” counties in the heart of the play rank near the top nationwide in drilling activity. For now, the primary focus of the small group of producers active in STACK (for “Sooner Trend Anadarko Canadian Kingfisher”) isn’t on production, it’s on gaining a more complete understanding of the play’s complex geology, which offers (as acronym luck would have it) a bona fide stack of hydrocarbon production layers (including the particularly promising Meramec) that together may offer off-the-chart volumes. Today, we consider a play that can provide some producers a 75% rate of return at $45/bbl oil and $2.25/MMBtu natural gas—that is, at prices 11% to 13% lower than they are today.
Crude oil prices have rebounded somewhat in recent weeks (and now are hovering near $50/bbl), but cash-hungry shale-play producers remain laser-focused on high-output “sweet spots” that promise quick, sure-fire economic returns. What if these same producers could get an added, low-cost boost in output—and much-needed revenue—through enhanced oil recovery (EOR)? EOR, which involves injecting or “flooding” seemingly past-their-prime oil wells with steam, carbon dioxide (CO2), natural gas or nitrogen to spur further production, has always been associated with conventional, vertical wells; but as we discuss today, there’s a push under way to make EOR work in horizontal wells too.
In February 2016, two months or so after the U.S. lifted its crude oil export ban, prices hit their lowest point in the current down-cycle that began in the summer of 2014. The ongoing price collapse had contributed to the favorable political winds in Washington, DC that resulted in lifting the ban. But what was favorable in the political realm posed severe commercial difficulties: U.S. producers were stuck with trying to sell into an international market awash in crude. Facing adversity, though, U.S. exporters have been getting creative, with the latest strategy involving backhauls of U.S. crudes on the same ships delivering foreign crude to U.S. ports. In today's blog, ClipperData's Abudi Zein looks at the market conditions that make such crude flows economically rational.
“Condensates are long and you can’t give them away … No, things have changed – condensate supply is tight and prices are running up relative to WTI … But wait wait, the oversupply is back and prices are down again.” No wonder the market’s love for condensates has faded. It’s a liquid hydrocarbon that is being buffeted by every force the market can bring to bear: declining production, lots of new committed infrastructure (stabilizers, pipelines, and splitters), wide-open export markets, volatile crack spread splitter economics -- the list goes on. Adding to this whirlwind is the fact that historically there has been limited analytical data to work with, with most condensate information buried deep inside crude production numbers from producer investor presentations and less-than-revealing Energy Information Administration (EIA) crude oil reports. But we have some new tools to help understand what’s going on, including the EIA’s new 914 crude quality data and condensate export numbers from ClipperData. Today, we continue our exploration of rapidly evolving condensate markets.
The reversal of Shell’s Zydeco Pipeline (formerly Ho-Ho) in 2013 was a big deal. It enabled eastbound flows of a wide range of crude streams from the Houston area to the storage and distribution hub at St. James, LA and from there to a dozen nearby refineries. Soon, though, Zydeco (named for the region’s Creole music) was running full and shippers were competing for space, spurring midstream companies to consider further enhancements. New pipeline capacity being developed is planned to come online later this year and in 2017, but—with ever-changing market dynamics—will it all be necessary? In today’s blog, “Take the Long Way Home—Easing Crude Pipeline Constraints to St. James,” Housley Carr begins a series on new pipeline capacity to St. James, and whether it will meet (or exceed) market needs.
Production in Alberta’s oil sands region is gradually rebounding after devastating wildfires that forced output scale-backs and temporary shutdowns of some production facilities, terminals and pipelines. It may be a while before life—and production—in the oil sands are back to normal, but Canada’s National Energy Board, producers and others expect the region’s output to continue to rise (if only gradually) the next few years, reflecting long-term oil sands expansion projects committed to when oil prices were more than double what they are today. There are very different views, though, about whether the oil sands will eventually need more takeaway capacity in the form of new or expanded pipelines. Today, we continue our look at the oil sands post-wildfires with a review of existing and proposed pipeline capacity.
Wildfires are notoriously unpredictable and, sure enough, as soon as the worst seemed to be over in the Fort McMurray, AB area, new flare-ups in mid-May threatened oil sands production areas north of the city. Thanks to heroic efforts by Alberta fire crews, no production area has experienced any significant damage (so far at least—fingers crossed), but a few work camps have been destroyed or damaged, and will need to be rebuilt. Good news is trickling in though, such as Imperial Oil’s May 19 announcement that it has restarted limited operations at its Kearl oil sands site. If, as everyone hopes, the wildfires are brought under control within the next few days, it seems likely that oil sands production will ramp up gradually over the next few weeks, and that by mid-summer Alberta’s output might be close to the 3.1 MMb/d that the province was producing before the fires were sparked.
Drill-rig counts and crude oil production are down sharply in the Eaglebine, one of many less-than-stellar shale plays that drillers and producers have mostly abandoned in favor of superstar counties in the Permian Basin, the southern Eagle Ford and the STACK play in Oklahoma. It’s understandable; in today’s low-oil-price/high-stress environment, everyone’s chasing the sky-high initial production (IP) rates that provide the biggest, quickest returns and help pay the bills. Still, as we will discuss today, there are at least a few glimmers of hope in the Eaglebine, including a possible pipeline restart and a new pipeline tie-in that will reduce crude-delivery costs. Now all we need is $60+/bbl oil.
