Crude oil production in the Rockies’ Niobrara region is up by more than 50% since the beginning of last year, spurred on by higher oil prices, ample oil pipeline takeaway capacity, and other positive factors. Natural gas and NGL production in the Niobrara — which includes both the Denver-Julesburg (D-J) Basin and the Powder River Basin (PRB) — has been rising too, to the point that there’s a scramble on to develop new gathering systems, gas processing plants as well as gas and NGL pipeline capacity. A number of exploration and production companies are upbeat about the region’s prospects; so are some midstreamers. But there’s a dark cloud on the horizon — at least in Colorado, where voters will decide in a few weeks whether to significantly restrict where new wells can be drilled. Is the Niobrara poised for continued growth or not? Today, we kick off a new series on Rockies production, infrastructure and prospects.
With a staggering 3.8 MMb/d of inbound pipelines, 3.1 MMb/d of outbound pipes and 94 MMbbl of storage capacity in between, the crude oil hub in Cushing, OK, surely has earned its nickname, “Pipeline Crossroads of the World.” But Cushing is more than a mere collection of pipelines and tankage, and crude doesn’t simply flow through the hub like cars and trucks flowing through a Los Angeles freeway interchange. Instead, much of the crude coming into Cushing from Western Canada, the Bakken, the Rockies, the Permian and other plays is mixed and blended within the hub, primarily to meet the specific needs of U.S. refineries and the export market regarding API gravity, sulfur content and the like. In other words, what goes in can be materially different than what goes out. Today, we continue our look at the central Oklahoma hub with an examination of the characteristics of the crude flowing in and out, and how they differ.
The price of northeastern Alberta’s key crude oil benchmark, Western Canadian Select (WCS), has been dropping like a rock. Last week, the heavy, sour blend of crude fell to a $45/bbl discount against U.S. benchmark West Texas Intermediate (WTI) — the biggest differential in at least 10 years. With an unplanned summertime outage at a Syncrude upgrader now over, Alberta production rising and pipeline takeaway capacity static — at least for now — the value of Canada’s crude may have even bleaker days ahead, despite a recent global rally in oil prices. Today, we explain why Western Canada’s oil producers are facing the prospect of mile-wide spreads for months to come.
Just as midstream companies are in a fierce competition to build new crude oil pipelines from the Permian to the Gulf Coast, there’s a race on to develop what would be the first Gulf Coast terminal in a generation capable of handling fully laden Very Large Crude Carriers. There’s a lot at stake. Currently, 2-MMbbl VLCCs can be filled to the brim without reverse lightering only at the Louisiana Offshore Oil Port (LOOP), and even if U.S. crude production continues to rise at a fast clip, it’s unlikely that more than another one or two high-capacity, VLCC-ready terminals would be needed over the next five years. And, assuming there’s not an overbuild situation, the project or projects that ultimately advance would be expected to be in-demand and highly utilized — VLCCs are the preferred mode of transporting crude to Asia and other far-away markets, and being able to fully load VLCCs saves the considerable cost and time associated with reverse lightering these supertankers in deep water. Today, we conclude our series on the fast-paced efforts to develop export terminals in waters deep enough to float VLCCs chock-full of oil.
The crude oil hub in Cushing, OK, is a big numbers kind of place: 94 million barrels of storage capacity, 3.8 MMb/d of inbound pipelines and 3.1 MMb/d of outbound pipes, not to mention a spaghetti bowl of connections between the many tank farms within greater Cushing. To truly understand the “Pipeline Crossroads of the World” — what it does and how it works — you need to know the hub’s assets and how they fit together. Today, we continue our series with a look at the pipes that transport crude from Cushing to Gulf Coast refineries and export docks, and to inland refineries in the Midcontinent, the Midwest and what you might call the Mid-South — places like Memphis, TN; El Dorado, AR; and Shreveport, LA.
China exceeded Canada as the largest buyer of U.S. crude exports for the first time in February 2017 and in year-to-date 2018 has averaged 378 Mb/d versus Canada’s 347 Mb/d. Ramping up purchases from virtually nothing in 2015 to more than 500 Mb/d in June 2018 was no small feat — the logistics in getting that much oil across the world include multiple ship-to-ship transfers, several weeks at sea and a whole lot of negotiating between U.S. crude marketers and the major Chinese buyers: Unipec and PetroChina. That already complicated process has recently been made just a little more complicated by the escalating trade war rhetoric between the U.S. and China. In today’s blog, which launches our new Crude Voyager service, we explain how crude flows to China are evolving.
Thanks to the shale revolution, U.S. refiners have spent the better part of the last two years achieving milestones in export volumes and run rates. The U.S. exported record volumes of gasoline and diesel last year. Much of that newfound international market share came at the expense of ailing refining complexes in Latin America, particularly in Mexico. That worked out great for U.S. refiners on the Gulf Coast, who could load up a tanker of fuel and have it delivered within a matter of days. Now the market on both sides of the border is shifting; the political landscape has changed in Mexico and gasoline demand growth in the U.S. is threatened by higher oil prices. Today, we lay out factors impacting exports and demand in the U.S. gasoline market.
Cushing doesn’t call itself the “Pipeline Crossroads of the World” for nothing. Pipelines with the capacity to handle one-third of total U.S. crude oil production flow into the central Oklahoma hub from a number of production areas, including the Alberta oil sands, the Bakken, the Rockies, the Permian and the nearby SCOOP/STACK. There’s almost as much pipeline capacity out of Cushing, with more than half of it bound for Texas’s Gulf Coast refineries and export docks and most of the rest headed for refineries in the Midcontinent and Midwest. Cushing’s inbound and outbound pipes connect to a staggering 94 million barrels of crude oil storage in about 350 aboveground tanks — each company’s set of tanks with its own unique degree of interconnectedness. Today, we continue our series on Cushing with a look at the large, medium and small pipelines that flow into the hub, and what they transport.
The crude oil hub at Cushing, OK, has more than 90 MMbbl of tankage, 3.7 MMb/d of incoming pipeline capacity and 3.1 MMb/d of outbound pipes. That’s an impressive amount of infrastructure by any standard. The real marvel of the place, though, is the variety of important roles it plays and services it provides for a wide range of market participants — producers, midstream companies, refiners and marketers, as well as producer/marketer and refiner/marketer hybrids. To truly understand Cushing — what it does and how it works — you need to know the hub’s assets and how they fit together. Today, we continue a series on the “Pipeline Crossroads of the World” with a look at the companies that own Cushing storage capacity and how that storage is put to use.
The late-August decision by Canada’s Federal Court of Appeal to overturn the Canadian government’s approval of the Trans Mountain Expansion Project will delay the project’s completion to at least 2021 or 2022. And — who knows? — the unanimous ruling may ultimately lead to TMX’s undoing, despite the Canadian government’s acquisition of the existing Trans Mountain Pipeline and the expansion project and its commitment to get TMX built. As producers in the Western Canadian Sedimentary Basin (WCSB) know all too well, TMX’s 590 Mb/d of incremental pipeline capacity would help to resolve ever-worsening pipeline takeaway constraints out of the Alberta oil sands and other production areas in the WCSB. These constraints are having a major economic impact every day — as evidenced by price differentials wide enough to run a locomotive through. Speaking of trains, crude-by-rail exports out of Western Canada reached a record 205 Mb/d in June, an 86% increase from the same month last year, and with WCSB production rising as new oil sands capacity comes online and with only limited relief likely on the pipeline capacity front from the Enbridge Line 3 Replacement Project in late 2019, many producers will need to depend on rail shipments of crude well into the 2020s. Today, we discuss the recent court ruling and what it means for Western Canadian producers, price spreads and the future of crude-by-rail.
The push to develop local sources of frac sand — and significantly reduce well-completion costs in the process — started in the Permian Basin, but it didn’t end there. A number of new sand mines are being opened and developed in the Eagle Ford in South Texas, and there are early signs the same is happening in the SCOOP/STACK in Oklahoma. With local sand eliminating the need for rail deliveries and rail-to-truck transloading terminals, sand and logistics companies are streamlining the delivery and management of frac sand by providing integrated mine-to-well-site proppant services. Today, we discuss recent developments on the frac sand front and what they mean for exploration and production companies in key plays.
It seems like everyone wants production out of the Permian these days — at least everyone who works for a pipeline company. The addition of five major greenfield crude oil pipes plus a host of expansion projects could bring Permian takeaway capacity up to 8.0 MMb/d from only 3.3 MMb/d today, with almost all of the incremental barrels destined for export markets. It’s a similar story for natural gas, with seven new pipes in the works to bring 2.0 Bcf/d each to Corpus Christi, Houston, or Louisiana, again with most of the molecules targeting exports. Not to be left behind, at least 27 new Permian gas processing plants are in development, and five new pipeline projects could bring 1.6 MMb/d of y-grade NGLs to the Gulf Coast. It’s a darned good thing that everyone in the global energy markets wants all that Permian production, right? What will this mean for the Permian and, for that matter, for the rest of the U.S. and the world? The only way to answer that question is to get the major players together under one roof and figure it out. That’s the plan for PermiCon 2018. Warning! Today’s blog is a not-so-subliminal advertorial for our upcoming conference.
The crude oil storage and distribution hub in the small town of Cushing, OK, is a marvel. With more than 90 MMbbl of tankage, 3.7 MMb/d of incoming pipeline capacity and 3.1 MMb/d of outbound pipes, Cushing’s nickname — “Pipeline Crossroads of the World” — is spot-on, not hyperbole. However, like a lot of other U.S. energy infrastructure in the Shale Era, Cushing’s role has been in flux. Permian oil production has been surging, the ban on U.S. oil exports is a fading memory, and the Gulf Coast — not Cushing — is where most U.S. crude production wants to go, for its concentration of refineries and export docks. That is not to say that Cushing is no longer important. Far from it. Today, we begin a blog series on how Cushing’s role has been morphing and why the Sooner State trading hub still provides critical support to producers, midstream companies and refineries alike.
There are common drivers behind the handful of offshore crude oil terminals now under development along the Gulf Coast, chief among them the well-founded belief that shippers would prefer putting crude on Very Large Crude Carriers (VLCCs), which can only be fully loaded in deep water. But each of these projects also has unique nuances — its own specific rationale and characteristics. Tallgrass Energy’s plan is a case in point in that it involves a new pipeline from the crude hub in Cushing, OK, to the refinery center in St. James, LA, and to a new onshore crude storage and loading terminal a few miles down the Mississippi River, to be followed by a VLCC-ready offshore terminal capable of both exporting and importing crude. Today, we continue our review of made-for-VLCCs offshore terminals with a look at Tallgrass’s effort to deliver neat, unblended barrels directly from multiple inland plays to deep water — “shale-to-ship,” in other words.
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.