The next wave of Permian crude oil pipeline infrastructure is getting completed as we speak. In West Texas, several new pipeline projects are either finalizing their commercial terms and agreements, wrapping up the permitting process, or actually putting steel in the ground. In the Permian alone, there is a potential for 4.3 MMb/d of new pipeline takeaway capacity to get built in the next two and a half years. Along with those major long-haul pipelines, there are also crude gathering systems being developed to help move production from the wellhead to an intermediary point along one of the big new takeaway pipes. While we often like to give pipeline projects concrete timelines with hard-and-fast online dates, the actual logistics of how producers, traders and midstream companies all bring a pipeline from linefill to full commercial service are never clean and simple. There can be a lot of headaches, learning curves, and expensive — not to mention time-consuming — problem-solving exercises that come with the start-up process. In today’s blog, we discuss why new pipelines often experience growing pains, and how market participants navigate the early days of new systems.
With Permian crude oil production now topping 4 MMb/d — and likely to surpass 5 MMb/d in short order — producers in the play are working closely with midstream companies to help ensure there is sufficient capacity in place to efficiently transport their crude from the lease to larger shuttle systems, regional hubs and takeaway pipelines. Sometimes, gathering systems need to be built from scratch, but in most cases, it is more cost-effective to expand existing systems that are already connected to key infrastructure downstream. Today, we continue our series with a look at a big pipeline network that NuStar Energy acquired two-plus years ago and has been expanding and improving ever since.
The competition to develop the one or possibly two new offshore crude oil export terminals that the U.S. will likely need by the mid-2020s has been under way for more than a year now, and the field of contestants continues to expand. Within the past few weeks, both Phillips 66 and Sentinel Midstream filed applications with the U.S. Maritime Administration (MARAD) — Phillips 66’s project would be located off the coast of Corpus Christi and Sentinel’s in the waters off Freeport. And who knows, maybe another deepwater project or two capable of fully loading Very Large Crude Carriers (VLCCs) might still be in the offing. Today, we update our series on prospective offshore crude export terminals with a look at the P66 and Sentinel project details revealed by their applications to MARAD.
Enbridge’s long-running effort to revamp how it allocates space — and charges for service — on its 2.9-MMb/d Mainline crude oil pipeline system is about to enter a new and important phase. On July 15, the Calgary, AB-based midstream giant plans to initiate an open season for shippers interested in locking up long-term capacity on the Mainline, which serves as the primary conduit for heavy and light crude from Western Canada to U.S. crude hubs and refineries. If all goes well, shippers will know by late in the year how much space they will have on the system starting in mid-2021, assuming Enbridge’s plan is approved by regulators. This is a huge change. The Mainline isn’t just the largest crude pipeline system out of Western Canada, it’s also the only major line whose service is currently 100% “uncommitted” — that is, the Mainline has no capacity under long-term contracts with shippers. Today, we discuss the latest on the midstreamer’s Mainline tolling plan.
For more than six months now, the provincial government of energy-rich Alberta has been trying to mitigate the sometimes painful effects of having too little pipeline capacity to move crude oil to market. They’ve mandated production cuts by larger producers, contracted for crude-by-rail (CBR) services — then moved to undo those deals — and pressed the Canadian government to help advance long-delayed pipeline projects. Things appear to have reached a semi-happy medium for now: the price spread between Western Canadian Select (WCS) and West Texas Intermediate (WTI) has narrowed, but remains wide enough to justify sending crude out by train. Still, it’s clear that the big tranches of new pipeline capacity many had hoped would be built or at least under construction by now face more hurdles. How long will Alberta producers need to wait for unfettered pipeline access to the U.S. Midwest and Gulf Coast and to Canada’s West Coast? Today, we provide an update on WCS pricing, Alberta crude-by-rail, and the key pipeline projects that never seem to get finished.
A key to success for midstream companies developing crude oil gathering systems in the Permian is establishing strong, trusting relationships with the producers driving the region’s growth. Hitch your wagon to one or more producers with top-notch rock and aggressive expansion plans, develop gathering systems that meet their needs for flow assurance and destination optionality, and life will be good. Many of the midstreamers whose Permian gathering systems we’ve been discussing in our ongoing series have done just that. Today, we review the existing and planned systems of EnLink Midstream, another company whose growth is founded in large part on the relationships it has developed with major Permian producers.
Crude oil exports out of the U.S. are the topic du jour these days. At the heart of the discussion are the who, what, where and when of how the export capacity will be developed. Who is going to build the next crude oil export terminal, what type will it be (offshore or onshore), where are they going to put it (Corpus, Houston, Louisiana — the list goes on), and when will that new capacity be available? Everyone seems to have a different answer, and for good reason. Crude oil export terminals aren’t easy to develop, any way you look at them. Today, we examine the financial and logistical hurdles that export terminals must clear in order to reach a final investment decision, and what those obstacles mean for what kind of terminal gets built, where it gets built, who builds it and how soon.
Most crude oil gathering systems in the Permian — and elsewhere — have a relatively simple aim: to reliably and efficiently deliver crude from the lease to larger pipelines downstream that provide their shippers a high degree of destination optionality — end of story. A select few systems, though, have evolved into key elements of their owners’ larger value chain. With these, crude flows through gathering systems and takeaway pipes to export terminals — maybe even refineries — all held by the same company or its affiliates. By integrating assets from the site of crude production to the refinery or export dock, such owners add value each step of the way. Today, we continue our series with a look at Marathon Petroleum/Andeavor Logistics’ Permian crude gathering system, which started out relatively small and isolated but has evolved into something much bigger and better connected.
A few months back, we discussed the quandary that crude oil shippers face when deciding whether to commit to proposed new pipeline capacity out of the Bakken and the Niobrara, and from the Cushing, OK, hub to the Gulf Coast. The dilemma boils down to this: more capacity is needed, based on current constraints or projected growth (or both), but there’s some reluctance among shippers to make long-term commitments. Their worries are that production gains might slow and too much takeaway capacity might be built, resulting in bidding wars for barrels at the lease to fill shipper commitments. Well, in recent weeks there’s been a bit of a break in the project logjam; among other things, P66 and its partners have decided to proceed with the construction of both the Liberty Pipeline, from the Bakken and Niobrara to Cushing, and the Red Oak Pipeline, from Cushing to Houston and Corpus Christi via Wichita Falls, TX. And that’s not all. Today, we provide an update on efforts to develop new pipeline capacity from North Dakota and the Rockies to Oklahoma and beyond.
For evidence of America’s unwavering entrepreneurial spirit, look no further than smaller midstream companies that develop crude oil gathering systems in the Permian. These midstreamers — many of them backed by private equity — scramble to identify production areas on the cusp of needing gathering lines, propose systems to serve them, convince producers to dedicate acreage, then lay pipe, install tankage and get things up and running. All of this occurs in an atmosphere of intense competition. A number of new and growing crude gathering systems are under development today in southeastern New Mexico, an area that has experienced more than its share of production growth in the past couple of years. Today, we continue our series with a look at 3 Bear Energy’s Hat Mesa Oil Gathering System in the northern Delaware Basin, which was developed from scratch in Lea County and now serves 10 producers there.
Crude oil production in the U.S. continues to rise — it currently stands at 12.4 MMb/d, up more than 1.6 MMb/d from 12 months ago, according to the most recent data from the Energy Information Administration (EIA). New pipeline projects from Cushing and West Texas to the Gulf Coast are being developed to ensure there is enough flow capacity to move all those barrels from the wellhead to refineries and export docks. Which leads to two critical questions — namely, how much actual crude oil export capacity is already in place at the Gulf Coast, and how much more needs to be developed? Today, we begin a series presenting our latest analysis of crude oil export capacity in the U.S., our forecast for total export demand, and our view of what it all means for the large slate of potential projects.
By their very nature, crude oil gathering systems in the Permian are works in progress. They often start out small, serving only a few wells owned by a single producer — or maybe two or three. Over time, the systems typically branch out to serve more producers and more wells, and they add capacity as drilling activity picks up. Sometimes, they evolve into much larger systems with multiple gathering hubs and regional transport pipelines that shuttle large volumes of gathered crude long distances to big marketing hubs like Crane, TX, and Midland, where the oil can flow into any number of takeaway pipelines to Cushing or the Gulf Coast. Today, we continue our series on Permian crude gathering systems with a look at Oryx Midstream’s 860-mile gathering and regional transport network in the super-hot Delaware Basin.
Refineries in Washington state have been reliable buyers of Bakken-sourced crude oil during the Shale Era, receiving an average of about 145 Mb/d — all of it by rail — over the past two-plus years. But a newly approved Washington law slashing the allowable vapor pressure limit for crude being unloaded from rail tank cars could hinder future growth in crude-by-rail shipments from North Dakota to the Evergreen State, or force Bakken producers to remove more butane and other “light ends” from the crude oil they rail west. It’s such a big deal that the state of North Dakota has indicated it will file suit to kill the new law. Today, we discuss Washington’s new law and its potential effects on Bakken crude oil producers.
On its surface, the development of small-diameter crude oil gathering pipeline systems in the Permian may seem like a ho-hum topic. In fact, though, these systems are at the heart of critically important strategies to ensure the reliable, low-cost flow of crude to multiple takeaway pipelines out of the basin, and thereby enhance the oil’s value and minimize financial risk. A case in point is the 50-mile-plus, 100-Mb/d-capacity gathering system that a producer/midstreamer joint venture has been building in the Delaware Basin along the Texas/New Mexico line. Today, we continue our series on Permian gathering systems with a look at WPX Energy and Howard Energy Partners’ new pipes in New Mexico’s Eddy County and Texas’s Loving and Reeves counties.
When it comes to getting crude oil to market, bottlenecks have always existed. Back in 2013-15, producers and shippers in the Rockies faced a serious lack of takeaway options. Midstreamers saw the problem and the money to be made, and quickly built more crude-by-rail capacity — and, over time, pipeline capacity — to fix things. Recently, major takeaway constraints emerged in the Permian, much to the detriment of netbacks at the wellhead. There was real concern for a few months that some producers might need to shut in production as there wasn’t any way to get incremental barrels out of the basin. Again, traders and midstream operators got savvy, restarted some dormant crude-by-rail options, initiated long-haul trucking out of Midland, and added more pipe capacity. But what if the next big bottleneck isn’t between two land-based trading hubs? What if there’s not enough export capacity at terminals along the Gulf Coast, the gateway to international markets? In today’s blog, we examine recent export and production trends, and discuss what those could mean for export infrastructure and logistics over the next five years.