Eight years into the Shale Revolution –– and two years into a crude oil price slump that put the brakes on production growth –– midstream companies continue to develop new pipelines to move crude to market. As always, the aims of these investments in new takeaway capacity may include reducing or eliminating delivery constraints, shrinking the price differentials that hurt producers in takeaway-constrained areas, or giving producers access to new markets or refineries access to new sources of supply. Whatever the economic rationale for developing new pipeline capacity, midstreamers and potential crude oil shippers need to examine–– early on –– the likely capital cost of possible projects, if only to help them determine which projects are worth pursuing, and which aren’t. Today, we begin a series on how midstream companies and potential shippers evaluate (and continually reassess) the rationale for new crude pipeline capacity in today’s topsy-turvy markets.
There is a story behind every new crude oil pipeline built to supply a decades-old refinery. After all, the refinery surely had a well-established crude-delivery system in place –– why change horses now, especially with refinery margins under so much pressure? Typically, the answer is that, well, times have changed. Or, more specifically, the Shale Revolution has up-ended traditional crude sourcing, forced refinery owners to rethink their crude slates, and opened up opportunities to access new, lower-cost oil. Today, we continue our look at these new pipeline connections, their rationales, and their effects on other pipelines, barge deliveries and crude-by-rail.
New pipelines to increase crude oil takeaway capacity from major producing areas like the Permian and the Bakken to oil storage and distribution hubs like Houston, TX and Cushing, OK seem to garner most of the media’s attention. Just outside the spotlight’s glare, though –– and even during the ongoing slump in oil prices –– midstream companies are building several “demand-pull” pipelines to move crude to refineries more efficiently, and to give refineries easier, cheaper access to new, desirable supplies. Today, we begin a look at these new pipeline connections, their rationales, and their effects on other pipelines, barge deliveries and crude-by-rail.
The 450-Mb/d Dakota Access Pipeline (DAPL) has broken away from the pack of out-of-the-Bakken crude takeaway projects. On August 2, Enbridge Inc., through its master limited partnership Enbridge Energy Partners, agreed to take a large stake in DAPL from Energy Transfer Partners (ETP) and Sunoco Logistics Partners (SXL), a move that suggests Enbridge’s own 225-Mb/d Sandpiper Pipeline may drop out of the race soon. Joining Enbridge in the $2 billion deal is Marathon Petroleum, its former joint venture partner and anchor shipper on Sandpiper. Today, we consider these recent developments in the long-running effort to transport North Dakota crude oil to market more efficiently.
West Texas Intermediate (WTI) crude oil at Cushing is languishing back in the low $40s/bbl after a brief period of exuberance in the late spring. The blame for this latest oil-price retreat has shifted from high inventories of crude oil –– both on land and on tankers floating offshore –– to bloated petroleum-product inventories. There is some debate about how concerned the market should be about the increase in product stocks. In the opening episode of this blog series, we take a look at petroleum product cargo flows, and what they are telling us about the health of the market. We start today with middle distillates –– diesel and jet fuel.
In the past century and a half, Sarnia, ON has evolved into one of Canada’s leading refinery and petrochemical centers, and a major consumer of Alberta and Bakken crude and Alberta and –– more recently –– Marcellus/Utica natural gas liquids. Getting that oil and those NGLs to southwestern Ontario is the task of a small group of pipelines and a few rail facilities; other pipelines out of Sarnia help to move refined petroleum products to nearby demand centers. Today, we continue our comprehensive review of refinery and petchem-related infrastructure in and around Ontario’s Chemical Valley.
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.
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 , 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.
A few weeks back Rusty Braziel sat down with Don Stowers, Chief Editor of Pennwell’s Oil & Gas Financial Journal, to talk about the big picture – some of the most important issues facing the oil and gas industry, the lasting impact of the Shale Revolution, and Rusty’s thoughts from 40-plus years in the energy business. It turned into the cover story of their June 2016 issue. Today, we recap a few of the interview questions. You can download the full article (along with Rusty’s smiling face on the cover) at the bottom of the blog.
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.