The Race Is On - Houston Crude Oil Futures Contracts Compete for Market Share

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.

Train in Vain - Why New Rail Car Specs are Creating Obstacles for Crude-by-Rail

It’s been well-reported that crude oil pipeline capacity is getting maxed out in many basins across the U.S. and Canada. From Alberta, through the heart of the Bakken, all the way down to the Permian, pipeline projects are struggling to keep up with the rapid growth in some of North America’s largest oil-producing regions. Crude by rail (CBR) has frequently been the swing capacity provider when production in a basin overwhelms long-haul pipelines. While it is more expensive, more logistically challenging, and more time-intensive, CBR capacity is typically able to step in and provide a release valve for stranded volumes. But recently, CBR capacity has been tougher to come by and has taken longer than expected to ramp up. A key aspect of this issue is a new requirement for up-to-date rail cars. Today, we look at how new rail demands and uncertainty in domestic oil markets are combining to create a major hurdle for new CBR capacity.

Pump It Up - Permian Natural Gas: More Production, Infrastructure and Demand

Right now, pipeline capacity out of the Permian is constrained, and consequently some producers have cut back on well completions, more gas is getting flared, and ethane recovery is being driven more by bottlenecks than by gas plant economics.  But even with these issues, there are still 487 rigs drilling for oil in the basin (according to Baker Hughes), and all will come along with sizable quantities of natural gas.    Not only does this production need to be moved out of the Permian, the volumes need to find a home — either in the domestic market or overseas. These were all issues that were considered by our speakers, panelists and RBN analysts last month at PermiCon, our industry conference designed to bridge the gap between fundamentals analysis and boots-on-the-ground market intelligence.  In today’s blog, we continue our review of some of the key points discussed during the conference proceedings.

Darkness into Light - Domestic Light Oil Processing in the USGC: Have We Hit the Limit?

Refineries along the U.S. Gulf Coast (USGC), which account for half of the country’s total refining capacity, are generally among the most sophisticated and complex anywhere, with configurations that enable them to break down heavy, sour crude oil into high-value, low-sulfur refined products. However, over the past eight years, the USGC has been flooded with increasing volumes of light, sweet crudes produced in the Eagle Ford, the Permian and other U.S. shale plays as new pipelines were constructed or reversed to the coast for domestic refining or export. Still more pipelines will be coming online over the next year. Today, we evaluate how much domestic crude oil has been absorbed into the USGC refining system, the implications to the overall crude slate qualities, and options for increasing domestic crude oil processing in the near term.

Push Me, Pull Me, Part 2 - Is The Bakken Facing Another Round of Crude Takeaway Constraints?

Pipeline capacity constraints are nothing new to producers in the Bakken. Prior to the completion of the Dakota Access Pipeline (DAPL) in mid-2017, market participants had been pushing area pipeline takeaway to the max. When DAPL finally came online following a lengthy political and legal battle, producers and traders were able to breathe a sigh of relief. But with Bakken production steadily increasing over the past 18 months and primed for future growth new constraints are on the horizon. Over the next year or so, Bakken output could overwhelm takeaway capacity and push producers to find new market outlets. The questions now are, which midstream companies can add incremental capacity, how much crude-by-rail will be necessary, and is there a chance a major new pipeline gets built? Today, we forecast Bakken supply and demand, discuss some upcoming projects and lay out the possible headaches for Bakken producers heading into 2019.

Rocky Mountain High? Part 2 - Niobrara Crude Production Growth and Takeaway Pipelines

Crude oil production in the Niobrara region in northeastern Colorado and eastern Wyoming has quadrupled since the start of the 2010s, and now tops 600 Mb/d. Fortunately for producers in the Niobrara’s Denver-Julesburg (D-J) Basin and Powder River Basin (PRB), midstream companies not only developed enough new pipeline takeaway capacity to transport all those incremental barrels, they overbuilt. As a result, the region — unlike the Permian and Western Canada — currently has no crude-oil pipeline constraints, something that makes the Niobrara even more attractive to producers. But part of a pipeline system now moving crude out of the D-J is being repurposed to carry NGLs instead, and with D-J and PRB crude production still rising, you’ve got to wonder, is a takeaway shortfall on the horizon? Today, we continue our series on the Rockies’ premier hydrocarbon production area and the infrastructure needed to serve it, this time focusing on crude oil.

Colder Weather - Gas Storage Inventories Are Near Historic Lows. What If This Winter Turns Frigid?

U.S. natural gas supply continues to set all-time records, and strong production growth is expected to continue. Most of these supply gains will come from the Northeast, where another round of pipeline capacity additions are being completed. But despite all this incremental gas output, a combination of cold weather last winter and hot weather this summer means that U.S. gas storage inventories are likely to end the fall season at their lowest levels since 2005. And even this comparison understates how low inventories are — gas consumption has grown dramatically in the past 10 years, and storage inventories are at all-time lows when considered in terms of the number of days of average consumption. Today, we begin a series on the implications of historically low gas storage inventories, including what the gas market might look like if this winter turns out to be colder than normal.

Push Me, Pull Me - What's Going On With Bakken Prices? And Are Constraints on the Horizon?

The discount for Bakken crude prices at Clearbrook to WTI at Cushing has been on a rollercoaster in recent weeks, widening from $1.30/bbl at the beginning of September 2018 to over $10/bbl in mid-October and narrowing again most recently. There are several factors at play here. Canadian production has overwhelmed area pipelines and prices are being heavily discounted. These cheap Canadian barrels are creating oversupply issues at markets that Bakken barrels also trade into. On the demand side, Midwestern refiners are in the middle of seasonal turnarounds, reducing the demand for both Bakken and Canadian grades. Meanwhile, Bakken production growth continues to steadily chug along, increasing by over 150 Mb/d since the beginning of the year. And while this recent Bakken price angst is cause for concern, there is a looming bottleneck for pipeline space that could really shake things up sometime next year. Today, we examine the recent price phenomenon, the relationship between Canadian crude differentials and Bakken prices, and why producers should be concerned about future pipeline shortages.

I'm Already There - Will the Swordfish Project Give LOOP a Leg Up in Crude Exports?

Time and again, the repurposing of existing assets like pipelines and marine terminals to meet changing market needs has proven to be a winning approach. After all, if a lot of what you need is “already there” — as we said in today’s song title — why build something entirely new? That use-what-you’ve-got tack is a key driver behind MPLX and Crimson Midstream’s recently unveiled Swordfish Pipeline project, which by early 2020 would enable large volumes of crude oil to flow south from the St. James, LA, market hub to the Clovelly storage hub — a key crude distributor to area refineries and the jumping-off point for crude exports on fully loaded Very Large Crude Carriers (VLCCs) via the Louisiana Offshore Oil Port (LOOP). The companies also envision using other existing pipelines — including a possibly reversed Capline — as well as the soon-to-be-finished Bayou Bridge Pipeline to feed crude into Swordfish. Today, we review the MPLX/Crimson plan and assess how it might boost the export cred of LOOP, which is currently the only Gulf Coast port that can fill a 2-MMbbl VLCC to the brim without reverse lightering.

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