On December 18, 2015, Congress and President Obama ended the 40-year ban on U.S. crude oil exports to countries other than Canada. Today the arbitrage window doesn’t make much economic sense for most exports – Light Louisiana Sweet on the Gulf Coast is about the same price as Brent in the North Sea. But the prospect of selling crude abroad remains tantalizing for a depressed U.S. upstream, and U.S. producers have begun to consider the possibilities for more significant export volumes. But does the U.S. have the right stuff? Will the qualities of U.S. crudes be competitive in global markets? In today’s blog, we begin a series to consider the qualities of U.S. crudes that are likely to be favored by international crude buyers.
In connection with year-end 2015 earnings announcements, North American exploration and production companies (E&Ps) continued to announce large reductions in 2016 capital budgets. But the most dramatic news is that RBN’s analysis of a study group of 30 E&Ps indicates that these companies are finally expecting oil and gas production to fall in 2016 after a 7% gain in 2015. In today’s blog we update our continuing analysis of E&P capital spending and oil and gas production guidance.
The story of crude-by-rail (CBR) in North America is that of a victory of good old U.S. ingenuity over the lack of pipeline capacity that stranded booming shale oil production in 2012. The lower cost to market of “on-ramp” rail terminals allowed surging crude production a route to (mainly) coastal refineries - igniting a building boom over 4 short years that has left 82 load terminals and 44 destination terminals operating today - many of them now underutilized. Along the way monthly lease rates for rail tank cars that reached $2,750/month at the height of the boom are down to $325/month after the bust – with many lease holders paying daily rent to park their empty cars. Today we conclude our series reviewing the state of CBR today.
A year ago (April 2015) the price spread between Light Louisiana Sweet (LLS) the St. James, LA benchmark light crude and Permian West Texas Intermediate (WTI) delivered to Houston was roughly $2.50/Bbl. In the first quarter of 2016 – following the end of the crude export ban and the crash of crude prices below $40.bbl – that spread narrowed to 30 cents/Bbl. This price differential change has thrown a wrench into traditional Gulf Coast price relationships that encouraged the flow of crude east from Houston to Louisiana. Further changes are expected as pipeline projects due to be completed in the next two years will deliver Bakken and Permian crude direct to St. James. Today we wrap up our series on St. James with a look at changing crude prices and flows.
Our analysis shows that about 1.7 MMb/d of crude-by-rail (CBR) unload capacity has been built out and is operating in the Gulf Coast region today. According to Energy Information Administration (EIA) data for January 2016 an average of only 142 Mb/d was shipped into the region by rail in January 2016 down from a peak of just under 450 Mb/d in 2013 and an average of 235 Mb/d in 2015. In other words, the current unload capacity represents a whopping 12 times January 2016 shipments – a massive overbuild that is continuing today as new terminals are still planned. Today we look at the fate of Gulf Coast CBR terminal unload capacity.
The oil price collapse has opened a wide rift between high quality “good” assets, breakeven “bad” assets, and ruinous “ugly” assets. The consequences will impact energy markets for decades to come. In our recently published Drill Down Report, we demonstrate the differences between good, bad and ugly wells by examining the diversity of production economics across the Eagle Ford basin and why producers have been zeroing in on the counties——and areas within those counties—where initial production (IP) rates are highest, and preferably where large volumes of associated natural gas and natural gas liquids can be found as well. Today we consider Eagle Ford counties in more depth—their IPs, their internal rates of return (IRRs), and the number of new-well permit applications in each county in the first quarter of 2016.
Two midstream operators have added at least 13 MMBbl of crude storage to the St. James hub during the past 8 years (NuStar and Plains All American). These companies have invested in the hub because of its proximity to the Gulf Coast and pipeline connectivity to refineries throughout the Eastern U.S. and as far northwest as Edmonton, Alberta. St. James has also been an active recipient of crude flowing east across the Gulf by barge and tanker from the Eagle Ford via Corpus Christi. These crude movements require terminal, storage and blending facilities. Today we describe crude storage facilities at St. James.
Waterborne crude volumes (including imports) delivered to coastal refineries in Texas, Louisiana and Mississippi by domestic producers peaked at 27% of inputs in 2014 as regional plants processed increasing quantities of shale crude. Since then, these volumes have plummeted to 15% of inputs in March 2016 as Gulf Coast refiners have returned to more competitive imports instead. At the same time Eagle Ford crude volumes shipped along the Gulf Coast have fallen 28% this year in response to declining production and narrow price differentials between Texas and Louisiana ports. Gulf Eagle Ford crude now also plays a far smaller part in export markets than WTI grades. Overall exports have not increased since the end of the export ban but volumes to Canada have plummeted as shipments to other nations have increased. Today we review the shifts in waterborne flows across the Gulf Coast region.
Although California refineries initially met the criteria that spurred development of crude-by-rail (CBR) shipments to other coastal regions (lack of pipeline infrastructure and wide crude price differentials between stranded inland supplies and coastal alternatives) neither rail shipments or terminal build outs have made much of a dent in the Golden States’ crude supply. At their height in December 2013 CBR shipments into California reached 36 Mb/d – just 2% of the State’s 1.9 MMb/d refining capacity and they have since dwindled to a trickle. Today we examine the low pace of shipments.
U.S. crude oil production is finally falling in response to the collapse in oil prices that started in mid-2014. Output is now poised to drop below 9 MMb/d--700 Mb/d off its April 2015 peak—and the rate of decline is accelerating. That raises all-important questions of how low will production go, which shale basins will be hit the hardest, and the most important question of all - how much will oil prices need to rise to reverse those declines? Understanding the factors necessary to answer these questions is the focus of RBN’s latest Drill Down report that we highlight in today’s blog. The bottom line? All production economics is local.
In the five weeks since February 11, the price of WTI crude oil on the CME/NYMEX spiked 50%, up from $26/bbl to $40/bbl (see black dashed circle in Figure #1). For hedge funds that took long positions in February, it was an awesome trade. And for beleaguered producers, it was certainly a bit of good news. But there are no celebrations in the streets of Houston and Oklahoma City. The fact that $40/bbl should be considered “good news” is sobering: Eighteen months ago, that price level would have been seen as a catastrophe for the producing community. In fact, it still is. In today’s blog we examine the factors that help push prices above $40/bbl and what it will take to really get US production growing again.
Most of the crude by rail (CBR) shipments to 4 refineries in Washington State are ex-North Dakota from where rail freight costs are over $10/Bbl. Bakken crude from North Dakota competes at Washington refineries with Alaska North Slope (ANS) shipped down from Valdez, AK. Back in 2012 ANS prices were more than $20/Bbl higher than Bakken crude – easily covering the rail cost. In 2016 so far the ANS premium to Bakken has averaged well below the $10/Bbl freight cost making CBR shipments uneconomic. But as we discuss today - Northwest refiners are still shipping significant volumes of crude from North Dakota.
In January 2016 the ICE futures Exchange changed the expiration calendar for its flagship Brent crude contract. The March 2016 contract expired on January 29, 2016 under new calendar rules that stipulate expiration one month and one day prior to delivery. This was done belatedly to reflect a change in the assessment of the physical Brent market that was implemented back in January 2012. On paper the change is just an overdue action by ICE to properly align the timing calendar for their popular futures contract with the underlying physical market. But in practice - as we suggest in today’s blog, the change has significant impacts on the calculation and analysis of the commonly utilized spread between ICE Brent (the international benchmark crude) and the U.S. equivalent West Texas Intermediate (WTI) crude futures contract traded on the CME/NYMEX.
If East Coast refiners bought their crude at the wellhead in North Dakota during February 2016 they would have paid average prices of about $4.90/Bbl below U.S. Benchmark West Texas Intermediate (WTI) at Cushing, OK – which works out at about $26.25/Bbl (price estimates from Genscape). If they shipped that crude by rail to refineries in Philadelphia, PA on the East Coast they would have paid about $14/Bbl rail freight - meaning the delivered cost of crude would be $26.25 + $14 or $40.25/Bbl. Alternatively they could have simply imported Bakken equivalent light sweet crude priced close to international benchmark Brent for an average $34/Bbl – saving a minimum of $6.25/Bbl. Today we describe how these economics have had a detrimental impact on crude-by-rail (CBR) shipments to the East Coast.
For the past, year many shale oil producers have defied the expectations of many and kept output at or near to record levels in the face of falling oil prices and much tougher economics. Improvements in productivity, cost cutting and a concentration on “sweet spot” wells that generate high initial production (IP) rates have all helped cash strapped producers survive. But with oil prices so far in 2016 stuck in the $35/Bbl and lower range and with the worldwide crude storage glut still weighing on the market – producers are finally pulling back. Today we look at how increased pressure on North Dakota producers is putting the brakes on Bakken crude production.