The latest estimates from North Dakota show production edging up in March 2015 after a two-month decline. But the heady days are over for the moment - in the wake of lower crude prices - as even optimistic forecasts project flattened growth. Meanwhile combined rail and pipeline crude takeaway capacity out of North Dakota are already far higher than production – but new projects like the TransCanada Upland pipeline continue to be pitched to shippers. Today we describe how that could result in producers switching from existing routes.
Posts from Sandy Fielden
[Note: We will not post an RBN Blog on Memorial Day - Monday May 25]
The past four years have seen a boom in U.S. refining with strong margins and increased throughput. The balance of refinery feedstock has changed from a majority of imports to a majority of domestic crude. Market inefficiencies – in the distribution system, crude quality mismatches and export restrictions have kept U.S. crude prices below international levels – bringing refiners high margins and competitive product exports. Today we look at how refiners have benefited from changing U.S. crude supplies.
Crude oil production is expected to be slowing down in U.S. shale basins in the wake of lower oil prices and drastic cuts in the number of working rigs. Most forecasts for future growth are far more conservative now. Yet new midstream pipeline projects continue to emerge. The latest proposal in the Bakken would add a minimum of 220 Mb/d of takeaway capacity sometime after 2018. At that point, between rail and pipeline, North Dakota takeaway capacity will be more than double RBN’s Growth Scenario production forecast – suggesting new pipelines will need to attract defectors from existing routes to market. Today we examine the rationale behind the proposed TransCanada Upland pipeline.
Fuel oil demand has been declining for years on dry land – under attack by regulators anxious to reduce sulfur emissions. New international regulations introduced in January of this year are designed to further reduce sulfur emissions from ship engines burning marine fuel oil (“bunkers”) at sea. The new regulations have had an immediate impact on the market for 1% sulfur fuel oil. Most affected ship owners are now using more marine gasoil in coastal zones. Today we examine how the new regulations have impacted fuel oil markets.
Last Friday (May 8, 2015), Baker Hughes data showed the Permian basin oil rig count up by two – suggesting that drilling may be picking up in West Texas. A week earlier at the end of April, Enterprise Products Partners (EPD) announced they are moving ahead with a new pipeline from the Permian basin to the Houston area – set to come online in 2017. The new pipeline will add 540 Mb/d of takeaway capacity and comes on top of 450 Mb/d being added in the Permian this year by the Plains All American Cactus and Energy Transfer Partners Permian Express II pipelines. Today we look at the new project and whether the incremental takeaway capacity is necessary.
In April officials from Mexican national oil company PEMEX expressed confidence that their January 2015 application to the Department of Commerce, Bureau of Industry and Security (BIS) for a license to export U.S. crude under a swap arrangement will soon be approved. The swap would involve Mexico importing U.S. light crude and U.S. refiners buying an equivalent volume of Mexican heavy crude. The transaction would bypass decades old U.S. crude oil export restrictions and indicate a further loosening of the rules after moves to allow condensate exports last summer. In today’s blog “Have Another Swap of Mexican Crude - Will A New Route Open for U.S. Crude Exports?” Sandy Fielden examines the proposed exchange.
In January 2015 new international regulations came into force that reduced the permitted sulfur content in ships “bunker” fuel in Northern European and North American coastal regions. The change has required vessels travelling in those zones to use more expensive fuels or install scrubbers to remove sulfur. The changeover was expected to cause a sharp increase in shipping costs but as we discuss in today’s blog, so far the impact has been far less painful than expected, at least so far.
According to the Energy Information Administration (EIA), liquids production from the Utica shale in Ohio (identified as crude oil but more likely all lease condensate) has more than trebled since January 2014 from 19 Mb/d to a projected 64 Mb/d in May 2015. Regional production of plant condensate from natural gas processing has also increased with the build out of gas processing capacity in the Utica and nearby Marcellus plays and could reach 50 Mb/d by the end of 2015. Midstream companies have been busy developing infrastructure to get this condensate to market. Today we look at developing infrastructure and markets for Utica condensate.
Data from our friends at Genscape indicates that an average 150 Mb/d of Bakken crude is being unloaded at the Plains All American and NuStar Energy partners rail terminals at St. James, LA. That is down from 250 Mb/d just two years ago (April 2013) but still represents a substantial target for pipeline developers to aim for. The first significant project to offer pipeline service from North Dakota to St. James is being developed by Energy Transfer and Phillips 66. Today we review the project details.
Data from the new Energy Information Administration (EIA) monthly report on crude-by-rail (CBR) shows a marked increase in shipments out of the Rockies during 2014 as production outstripped pipeline capacity. The data history EIA provides also shows that significant CBR movements within the Gulf Coast region (presumably out of the Permian) occurred in 2013 when crude price differentials helped rail economics. Rail shipments to California from Texas have yet to take off however. Today we wrap up our analysis of monthly EIA CBR data.
The major re-plumbing of the U.S. crude pipeline distribution network to get 4 MMb/d of new domestic production as well as incremental Canadian barrels delivered to refineries is getting close to completion. The price crash and an expected slow down in production will almost certainly slow the pace of infrastructure development. The result is likely to be intensified competition between rival midstream companies and industry consolidation. Today we look at the larger implications of a small pipeline project in Houston.
The flood of domestic light shale crude showing up at the Texas Gulf Coast by pipeline in the past two years is not best matched to most refineries in the region that are configured to run heavier crude. But flows across the Gulf Coast to refineries in the Mississippi Delta more suited to process light crude are constrained by a lack of pipeline capacity between Texas and Louisiana. New domestic shale crude has been delivered to eastern Gulf Coast terminals such as St. James by rail but narrowing coastal differentials to inland prices have reduced the CBR advantage. Today we detail how new pipeline projects promise to increase the flow of crude from Texas to the Eastern Gulf.
The Plains All American (PAA) Cactus Pipeline comes online in the West Texas Permian this month (April 2015). Cactus will bring up to 250 Mb/d of crude and condensate from Midland and McCamey in the Permian to Gardendale, TX - the heart of the Eagle Ford shale – linking the two basins for the first time by pipeline. It also forms a major component of an expanded pipeline and dock infrastructure owned by a combination of PAA and Enterprise Product Partners (EPD) set to deliver as much as 600 Mb/d of crude and condensate to Corpus Christi and 470 Mb/d to Houston by the end of 2015. Today we describe how a good deal of those deliveries will be processed condensate eligible for export.
Data from the new Energy Information Administration (EIA) monthly report on crude-by-rail (CBR) shows that shipments from Canada increased from less than 10 Mb/d two years ago in January 2012 to over 130 Mb/d in January 2015. The increase in CBR movements mirrors increasing Canadian crude exports to the U.S. – the majority of which are still pipeline movements. Today we look at the destination markets for Canadian CBR in the light of congested pipeline capacity out of Western Canada.
Data from the North Dakota Industrial Commission (NDIC) indicate that production in January 2015 slowed by 37 Mb/d from record levels over 1.2 MMb/d in December. The number of new well completions also slowed in January – leading to a large backlog of wells drilled and waiting to start producing. Lower production and completions are in part due to producer caution following the crude price crash last year but producers waiting for a North Dakota state tax break and the usual impact of winter weather could also be responsible. Today we describe how new state tax incentives could boost summer output back to record levels.