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.
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.
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.
Crude prices are hovering around $30/Bbl making crude–by-rail (CBR) transport an expensive option for hard pressed producers looking to conserve cash – especially where pipeline alternatives are available. The crude price differentials that once justified shipping inland crude to coastal destinations by rail have all but disappeared. In November, 2015 pipeline shipments exceeded rail out of North Dakota for the first time since 2011 and by 2017 available pipeline capacity out of the region should exceed producer’s needs. In the circumstances, rail shipments would appear to be living on borrowed time but as we describe today - some North Dakota rail shipments are continuing in spite of the poor economics.
The 20 Mb/d Dakota Prairie refinery commenced operation on May 4, 2015 – becoming the first brand new U.S. crude processing plant to startup in nearly 40 years. The rationale behind this refinery and plans for others like it was surging demand for diesel driven by the shale oil boom in North Dakota. However the market conditions that prompted interest in building refineries in the Bakken region have changed considerably in the past year and led to an unprofitable first quarter for Dakota Prairie. Today we explain why the new refinery made sense at one time and what has changed in the past year.
Delays to the Enbridge Sandpiper project bringing greater volumes of Bakken crude onto the Enbridge Mainline system at Superior, WS threaten to limit the supply of crude to feed refineries in Quebec when Enbridge’s Line 9B reversal project comes online in November 2015. The market impact could push crude prices higher in North Dakota. Today we discuss the crude supply picture and possible impact when Line 9B opens up.
Crude oil producers in the Bakken region responded to the oil price collapse with drilling cutbacks and a laser-like focus on sweet-spot areas with high initial production rates. It turns out those oil sweet spots also produce a lot of associated natural gas. But there’s not enough infrastructure in place to deal with the extra gas, and that’s slowing North Dakota’s efforts to reduce flaring (burning gas that can’t be utilized for various reasons). Today, we consider the multiple, domino-like effects that low oil prices are having on one of the U.S.’s most important tight oil plays.
This month the North Dakota Industrial Commission (NDIC) indicated they are leaning towards leniency in their treatment of operators that have drilled but not completed wells within the one-year time frame permitted. Instead of assuming such wells are abandoned, which would otherwise mean an expired drilling permit and about $200,000 in plugging costs, – the State plans to give operators more time. That possibility opens up a whole new underground storage option for producers struggling to make ends meet. Today we explain the NDIC plan.
Crude by rail (CBR) shipments from North Dakota to West Coast destinations peaked in January 2015 at 170 Mb/d – falling since then to average 140 Mb/d in 2015, January through May. The vast majority of these shipments have moved to four refineries in Washington State – providing a cheaper alternative to the Alaska North Slope (ANS) crude staple these refineries have run for decades. There is big potential to expand CBR shipments to West Coast Ports and to California but building the infrastructure has proven painstakingly slow. Today we discuss the long term fate of West Coast CBR.
Yesterday (August 3, 2015) Brent crude closed under $50/Bbl for the first time since January 2015. At that price expensive crude-by-rail (CBR) freight costs to the East Coast leave Bakken producers with netbacks not much over $30/Bbl. Yet CBR shipments to the East Coast were still over 400 Mb/d in May 2015 according to the Energy Information Administration (EIA). By 2017 there should be adequate capacity to get all Bakken crude to market by pipeline. But direct pipeline competition against rail to the East Coast is not expected until at least 2020. Today we look at the future of East Coast CBR.
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.
Data from the Energy Information Administration (EIA) shows that inland barge movements between the U.S. Midwest and the Gulf Coast increased 10 fold between January 2011 and October 2013 to nearly 160 Mb/d in response to soaring crude production and pipeline congestion. Since then barge traffic on the Mississippi River (the main waterway between the two regions) plunged 80% to 27 Mb/d in April 2015 – the latest month reported. Today we explain why.
When the Apollo 13 astronauts realized their oxygen tanks were badly damaged, they famously said “Houston, we’ve had a problem.” Today, this phrase could well describe the U.S. oil and gas industry. The issue isn’t only today’s low prices, but also the industry’s resilience and its response to low prices. U.S. producers may have created a price ceiling for the world. Today we reflect on a new age of abundance in U.S. energy markets.
Oil-Weighted exploration and production companies (E&Ps) are slashing capital spending in 2015, as they need to regain control of their costs in today’s lower oil price environment. With robust oil prices over the past three years, these companies only posted middling profitability as capital and operating costs ate up much of their incremental revenue. The Large Oil Weighted E&Ps are cutting back less than the Small/Mid-Sized Oil Weighted E&Ps as they are more financially secure and have more ability to spend through the price cycle. The Small/Mid-Sized Oil Weighted E&Ps are focused on getting their spending in line with cash flows and to get to a point where they are self-funding their capital investment. Today we explore how each of the companies in the two oil-weighted peer groups is trying to resolve these issues.