Crude Oil

Monday, 05/23/2016

Production in Alberta’s oil sands region is gradually rebounding after devastating wildfires that forced output scale-backs and temporary shutdowns of some production facilities, terminals and pipelines. It may be a while before life—and production—in the oil sands are back to normal, but Canada’s National Energy Board, producers and others expect the region’s output to continue to rise (if only gradually) the next few years, reflecting long-term oil sands expansion projects committed to when oil prices were more than double what they are today. There are very different views, though, about whether the oil sands will eventually need more takeaway capacity in the form of new or expanded pipelines. Today, we continue our look at the oil sands post-wildfires with a review of existing and proposed pipeline capacity.

Wildfires are notoriously unpredictable and, sure enough, as soon as the worst seemed to be over in the Fort McMurray, AB area, new flare-ups in mid-May threatened oil sands production areas north of the city. Thanks to heroic efforts by Alberta fire crews, no production area has experienced any significant damage (so far at least—fingers crossed), but a few work camps have been destroyed or damaged, and will need to be rebuilt. Good news is trickling in though, such as Imperial Oil’s May 19 announcement that it has restarted limited operations at its Kearl oil sands site. If, as everyone hopes, the wildfires are brought under control within the next few days, it seems likely that oil sands production will ramp up gradually over the next few weeks, and that by mid-summer Alberta’s output might be close to the 3.1 MMb/d that the province was producing before the fires were sparked.

Sunday, 05/22/2016

Drill-rig counts and crude oil production are down sharply in the Eaglebine, one of many less-than-stellar shale plays that drillers and producers have mostly abandoned in favor of superstar counties in the Permian Basin, the southern Eagle Ford and the STACK play in Oklahoma. It’s understandable; in today’s low-oil-price/high-stress environment, everyone’s chasing the sky-high initial production (IP) rates that provide the biggest, quickest returns and help pay the bills. Still, as we will discuss today, there are at least a few glimmers of hope in the Eaglebine, including a possible pipeline restart and a new pipeline tie-in that will reduce crude-delivery costs. Now all we need is $60+/bbl oil.

Monday, 05/16/2016

It will take at least a few weeks, but it seems likely that production in the Alberta oil sands will return to near normal levels, setting the stage for continued incremental growth over the next few years as expansion projects committed to when oil prices were much higher come online.  Although fires are still burning, the devastation in and around Fort McMurray, AB--the unofficial capital of the oil sands region—that forced tens of thousands of people from their homes, prompting oil sands staffing shortages, production scale-backs and a handful of temporary production shutdowns has moved beyond most oil sands operations.  But the wildfires’ chain of effects didn’t end there; at one point, crude oil output declines were estimated at upwards of 1 MMb/d (about one-third of Alberta’s normal production of 3.1 MMb/d) caused world oil prices to inch up, some refineries in the U.S. Midwest that depend on Alberta-sourced oil have been forced to scramble for replacement crude, and natural gas prices fell to near zero for a brief period. Today, we begin a two-part look at post-wildfire prospects for the region, and—looking ahead--at the possible need for more pipeline takeaway capacity.

Tuesday, 05/10/2016

Few segments of the energy market have experienced the roller-coaster ride that U.S. condensates have been on over the past five years.   Prior to 2011, U.S. condensates were a forgotten backwater of the hydrocarbon complex, mostly blended off into crude oil.  Then condensates rapidly transitioned from obscurity to an oversupplied, price-discounted growth market, then to a driver of massive infrastructure investment, then to the star of the show as the only member of the U.S. crude oil family that could be exported.  By mid-2014, producers and midstreamers were in love with condensates.  Exports were legal and growing.  New pipeline, splitter, stabilizer and export dock infrastructure was coming online.  U.S. condensate markets were tightening and condensate prices were increasing.  Then in one fell swoop in December 2015, Congress swept away all export restrictions on crude oil, potentially relegating U.S. condensates back to the obscurity from whence they came.

Monday, 05/09/2016

A few years back, crude-by-rail (CBR) emerged as the go-to fix that enabled pipeline-constrained shale regions to move fast-increasing volumes of oil to market. A total of 178 rail terminals were built or significantly expanded, with 99 loading terminals and 79 unloading terminals developed in the U.S. and Canada.  But changes in the market -- lower oil prices, slowing/declining production, new pipeline capacity -- have been challenging and undermining CBR.  Only about 20% of U.S. nameplate capacity is being used, and further declines in CBR volumes are expected, prompting serious questions about CBR’s future role.  Today, we discuss RBN Energy’s latest Drill Down Report, which examines CBR’s pros and cons, its evolution, and its current status and prospects.

Thursday, 05/05/2016

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.

Tuesday, 04/26/2016

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.

Sunday, 04/24/2016

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.

Tuesday, 04/19/2016

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.

Sunday, 04/17/2016

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.

Wednesday, 04/13/2016

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.

Monday, 04/11/2016

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.

Thursday, 03/31/2016

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.

Tuesday, 03/29/2016

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.

Monday, 03/28/2016

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.