Crude Price Crash

West Texas Intermediate (WTI) CME NYMEX crude futures settled up 92 cents/Bbl yesterday (January 28, 2016) at $33.22/Bbl and NYMEX Henry Hub natural gas futures settled up slightly at $2.182/MMBtu. The crude-to-gas ratio - meaning the crude price in $/Bbl divided by the gas price in $/MMBtu - was 15.22 X. For most of this year so far the ratio has been less than 15X On January 20, 2016 it dipped to 12.5 X – its lowest point since March 2009. Over the 5 years between 2010 and 2014 the ratio averaged 27X - reaching a high of 54X in April 2012. That lofty five year run for the crude-to-gas ratio was arguably responsible for much of the crude and natural gas liquids production boom since 2011 and a “Golden Age” of natural gas processing. Today we begin a two-part series discussing the ratio and the market implications if it stays low.

Bakken crude-by-rail (CBR) volumes are down this year and pipeline shipments are increasing as production levels off in the wake of last year’s price crash. The trend is encouraged by lower price differentials between domestic and international crude as well as new pipelines coming online. Since 2012 a combination of rail and pipeline has given Bakken producers ample crude takeaway capacity but pipelines alone have not had sufficient capacity on their own. However, with production slowing down, pipeline capacity is catching up and by 2017 there should be enough pipelines to carry all North Dakota’s crude to market. Today we start a two part series asking whether pipelines can replace CBR from North Dakota.

If it persists, the oil price crash may have undermined many of the assumptions behind massive infrastructure investments in steam cracker plants and export facilities for natural gas liquids (NGLs). These projects expected to take advantage of booming domestic NGL production and low NGL prices relative to crude. Yet take-or-pay commitments and committed investment in plant infrastructure means they may be exposed to  poor returns if crude prices remain low. Today we detail analysis in the latest RBN Energy Drill Down Report to develop NGL supply, demand and pricing scenarios.

Producer rates of return are far below where they were a few months back, and the Baker Hughes crude rig count is down 553 since November. A third of pre-crash crude rigs are now idled. That means that crude oil production will be falling soon, right?  Not necessarily.  There are a number of factors working to keep production up, not the least of which is the rapidly declining cost for drilling and completion services.  Today we examine the impact of these factors, review RBN’s crude oil production scenarios and consider what it all means for the long-term relationships between prices, returns and production volumes.

While producers are licking their wounds after a more than 50% oil price crash, refiners have continued to enjoy healthy margins – even in the face of the largest refinery strike since 1980. Strong refining margins, supported by an ongoing boom in refined product exports, continue to encourage high levels of refinery utilization in the Gulf Coast region – home to more than 50% of U.S. refining capacity. Today we look at how Gulf Coast refiners are faring after the oil price crash.

While many companies in the energy sector – particularly in the producer community – are licking their wounds and reporting lower profits and reduced capital expenditure to their stockholders this quarter, refiners have continued to thrive. Lower refined product prices have begun to increase domestic consumption of gasoline and diesel in the face of longer-term decline trends. And strong refining margins continue to encourage high levels of refinery utilization. Today we start a two-part look at how U.S. refiners are faring after the oil price crash.

It would be an understatement to say that the worldwide market for liquefied natural gas (LNG) is in flux. LNG production is up and heading higher, oil—and LNG--prices are down sharply from a few months ago, and Japan and other big consumers of LNG are more interested than ever in mitigating price and supply risk. All this comes as Japan, a primary target of prospective U.S. and Canadian LNG export projects, is grappling with the need to restart dozens of idled nuclear units so it can reduce the oil and LNG imports that have hurt its trade balance since the Fukushima disaster nearly four years ago. Today we consider recent developments and how they may affect Japan and its potential LNG suppliers on the North America side of the Pacific.