It’s been a big year for oil production from the Bakken formation in North Dakota with output passing the 1 MMb/d mark in April and expected to close out 2014 at 1.25 MMb/d. Crude netbacks (market price less transport cost from the wellhead) suffered during the first half of the year from narrowing coastal price differentials - denting the economics of crude-by-rail - the most popular option to get Bakken crude to market. Rail freight costs look set to increase in 2015 with new tank car regulations and requirements for wellhead treatment to remove volatile components. But those changes pale into insignificance compared to the recent crude price nosedive. That threatens to reduce producer revenues by billions of dollars in 2015 and puts the spotlight on higher transport costs to get crude to market from North Dakota. Today we look at the financial impact lower netbacks could have on Bakken producers.
If 2012 was “the year of the tank car” in North Dakota then 2014 could turn out to be the year when crude by rail economics turned sour for producers. New pipelines are coming online to deliver increased volumes of crude to the Gulf Coast with more projects on the drawing board. Safety issues and traffic congestion are raising the cost of rail freight. But the biggest challenge to rail is the pressure from narrowing crude price differentials between North Dakota and coastal markets. Producers can now get better returns shipping barrels by pipeline and in a falling price market they are more incented to make the switch. Today we explain why rail may be losing its edge.
Crude prices have fallen worldwide by about 20 percent since June 2014, as increasing supplies have not balanced with lackluster demand worldwide. Here in the U.S. prices for the benchmark West Texas Intermediate (WTI) grade have strengthened against international benchmark Brent as refiners continue to operate at high capacity. However, recent signs of discord in producer’s organization OPEC suggest they cannot agree to curb output – keeping downward pressure on overall prices. Today we wonder if there is a bottom to the current price slide.
The latest North Dakota Pipeline Authority (NDPA) data for April 2014 shows crude production in that State finally crossing the 1 MMb/d mark. That threshold was finally crossed after producers recovered from a harsh winter that shut in production and constrained new drilling. But while production continues to grow and is expected to reach 1.7 MMb/d by the end of 2019, producer crude takeaway preferences appear to be changing. NDPA data shows an 8 percent reduction in rail shipments out of North Dakota since November 2013. Today we investigate the shift away from rail transportation.
After tracking within $1/Bbl or so of each other for years, international benchmark Brent crude suddenly began to trade at a higher premium to US benchmark West Texas Intermediate (WTI) in 2010. The Brent premium widened out as far as $28/Bbl in November 2011 and averaged $18/Bbl in 2012. But during 2013 the relationship calmed down some to average $11/Bbl and in 2014 so far has averaged $8.11/Bbl – closing lower at $5.17/Bbl yesterday (June 10, 2014). Today we provide an update on the Brent/WTI crude price relationship.
Yesterday (April 30, 2014) the Energy Information Administration (EIA) reported yet another increase in Gulf Coast inventories as of April 25 - adding 5.7 MMBbl to set a new record of over 215 MMBbl of crude. Stocks in the region are now 27 MMBbl above the 5-year average and even if refiners cranked up output to the highest levels ever (96.5 percent utilization) the surplus would take at least 3 months to get back to “normal”. Crude prices are being impacted as the premium of Light Louisiana Sweet (LLS) crude at the Gulf Coast over West Texas Intermediate (WTI) delivered to Cushing, OK has narrowed close to $2/Bbl. With no crude exports allowed to ease the surplus it looks like Gulf Coast prices will remain under pressure. Today we look at prospects of reducing the crude surplus.
The next six months look set to be quite turbulent for Permian Basin producers. Crude production is now over 1.5 MMb/d and supplies trying to get to market are facing congested pipelines leading to price discounts. New capacity is due online in June in the shape of the 300 Mb/d Magellan/Occidental joint venture BridgeTex pipeline. But many Permian producers are also awaiting the build out of gathering systems to deliver their crude to regional hubs in Crane, Midland and Colorado City where the major takeaway pipelines originate. At least a dozen of these systems are currently being developed. Today we start a new series on the build out of Permian gathering infrastructure.
In the eight weeks since January 24, 2014 crude oil stocks in the Gulf Coast region grew by 34 MMBbl to reach record levels. Much of the crude pouring into the Gulf Coast is coming by pipeline from Cushing where stocks have been draining over the same period. In addition the Gulf Coast is receiving increased domestic and Canadian supplies from the Midwest via waterway and rail as well as by pipeline from the Permian Basin and by pipeline and barge from the Eagle Ford. Existing Gulf Coast infrastructure is being strained by the challenge to stage crude supplies to area refineries. Today we describe increasing flows of crude into the Gulf Coast region.
There are no crude pipelines running from the Gulf Coast refining region to the West Coast. A Kinder Morgan plan to build such a pipeline last year (2013) floundered on lack of shipper interest. Surging crude supplies at the Gulf Coast and downward pressure on prices in the absence of an end to the crude oil export ban raise the tantalizing possibility of moving crude East to West through the Panama Canal (or the Transpanama pipeline). Today we look at the economics of such shipments.
This week on Monday WTI prices crossed the $100/Bbl mark for the first time since the end of December (they closed at $100.37/Bbl yesterday February 12, 2014). Brent crude traded at a $19/Bbl premium to WTI at the end of November but the spread has fallen to less than $10/Bbl in recent weeks ($8.42/Bbl yesterday). One of the biggest concerns hanging over the crude market is the fear of oversupply – both inside and outside the US – with the forward curves pointing towards WTI at $78/Bbl and Brent at $90/Bbl by 2020. Today we provide an update on the crude market.
Midstream companies are building or planning 400 Mb/d of new condensate splitter capacity to process Eagle Ford production by 2016. BASF/Total have been operating a 75 Mb/d splitter at Port Arthur since 2000. The new splitters are being built in response to a flood of condensate range material coming out of the Eagle Ford into Houston and Corpus Christi. So what’s the big deal with condensate splitters? Today we look at splitter economics.
This year has seen the WTI discount to Brent trading in a range from $23/Bbl in February to less than $1/Bbl in July then back out to $19/Bbl in November. On Friday (December 27, 2013) the WTI discount to Brent was $11.85/Bbl. During the year the spread behaved differently in three distinct periods - reflecting changes in the fundamentals as well as market sentiment. Today we review how the granddaddy of crude spreads fared this year.
If the flood of new crude arriving at the Gulf Coast during the first six months of 2014 overwhelms refiners in the region, then the pricing consequences may very well be quite radical. Could prices at the Gulf Coast flip to trade at a discount to West Texas Intermediate (WTI) crude delivered at the Cushing hub that is home to the CME NYMEX contract? Even if Gulf Coast crude retains its premium over WTI, deep discounts may be required to encourage refiners to process increasing quantities of light sweet crude. A downward spiral of crude prices could ensue. Today we lay out possible price scenarios.
The bases are loaded for another 2 MMb/d of pipeline capacity to bring additional crude supplies to the Texas Gulf Coast by the end of 2014. The majority of that payload will likely be light sweet crude from tight oil formations, a.k.a., shale. As the flood of crude headed to Texas passed through the Midwest over the past two years, prices at Cushing and points north were heavily discounted versus coastal markets. Now the discount action has moved to the Gulf Coast where light sweet crude imports have been pushed out. Today we look at the impact of the changing supply position on crude price differentials.
Throughout the three year-long disruption of the US crude oil distribution system caused by rising domestic and Canadian production trying to find a path through the Midwest, the Seaway pipeline reversal project has been a market bellwether of progress to unwind the congestion. In 2Q 2014 the final phase will come online - opening up an additional 450 Mb/d capacity between Cushing and Houston. As the Seaway project has been built out, the crude surplus in the Midwest appears to have moved to the Gulf Coast. Today we detail the impact of Seaway Phase 3 on Gulf Coast crude supplies.