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.
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.
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.
Last week (February 19, 2015) Enterprise Product Partners announced the start of line fill on their 780 Mb/d ECHO to Beaumont/Port Arthur pipeline. The new route will open access for Canadian heavy crude shippers on the recently completed Seaway Twin pipeline from Cushing to Houston to 1.5 MMb/d of refining capacity in Beaumont/Port Arthur including 0.3 MMb/d of heavy crude coker processing. These refineries were a key target of the Keystone-XL pipeline from Canada to the Gulf Coast that still awaits approval. Today we look at demand and competition for Canadian heavy crude on the Texas Gulf Coast.
Between them the TransCanada Grand Rapids, Enbridge Norlite and Devon/MEG Access pipelines currently being planned and built out will be able to deliver an extra 1 MMb/d of diluent to oil sands producers by 2017. That’s more than producers currently expect to need until 2030. The diluent will be shipped north from Edmonton terminals to production plants and blended with bitumen before making the return trip as dilbit or railbit destined for long-haul transport by pipe or rail to U.S. and Canadian markets. Today we describe the pipeline build out plans.
Enbridge expect their Line 9 reversal to be complete in October 2014. By the end of 2014 this pipeline will deliver 300 Mb/d of mainly light crude to two refineries in Quebec. But the Line 9 reversal will likely not have capacity to ship any crude for export – either from Canada’s East Coast or via the Portland-Montreal pipeline to Maine. Significant crude deliveries east of Quebec will have to wait for TransCanada’s Energy East pipeline in 2018. Today we explain why in the final episode of our series on feeding crude to eastern Canadian refineries.
With the Northeast natural gas market now dominated by physical flows from the Marcellus/Utica, Appalachia producers are targeting the Midwest, the Southeast and—the biggest prize of all—the LNG export projects under development along the Gulf Coast. Getting gas to market, however, requires a top-to-bottom re-plumbing of interstate pipelines originally designed to move gas from the Gulf Coast, not to it. In today’s episode of our series on moving gas out of the Marcellus/Utica we look at plans to add bi-directionality to pipelines within the Midwest and to the Gulf.
TransCanada currently owns just over 1 MMBbl of crude storage at Hardisty that is used to stage operations on the existing 580 Mb/d Keystone pipeline to the US. With two huge new pipelines planned to originate at Hardisty – the 830 Mb/d Keystone XL (still awaiting Presidential approval) and the 1.1 MMb/d Energy East potentially coming online in the next four years, the company is rapidly expanding Hardisty capacity. At the same time Gibson Energy and US Development Group are building a 120 Mb/d rail terminal close by to Hardisty that will give Canadian producers the option to bypass pipeline congestion. Today we describe these companies’ infrastructure plans.
Expanding Western Canadian Oil Sands production is currently butting up against pipeline constraints to move the crude to markets in the US and beyond. The result is painful price discounts for producers and an increased inventory of crude in storage at the Edmonton and Hardisty hubs in Alberta. New storage capacity is being added in both hubs to handle the growing volume. Today we detail TransCanada and MEG Energy expansion plans in Edmonton.
So far in 2013 around 645 Mb/d of new crude oil pipeline capacity has opened up to ship supplies to the Texas Gulf Coast. Early this month (December) line fill starts on the largest new capacity addition to date – the 700 Mb/d Keystone Gulf Coast Pipeline. The new pipeline runs from Cushing to Port Arthur and will carry mostly Canadian heavy crude. Today we wonder if all that crude will find a home.
The first episode in this series described 4 MMb/d of current and planned expansions to crude transportation capacity into the Texas Gulf Coast region (see Handling The Texas Gulf Coast Crude Flood). Our analysis showed that the new incoming light crude capacity will exceed Texas Gulf Coast demand by somewhere north of 0.5 MMb/d by the end of 2015. In episode two we described how some of these excess crude supplies would move east on the reversed Ho-Ho pipeline (see Gulf Coast Crude West to East Flows). In episode three we looked at how shippers could divert supplies away from Texas Gulf Coast congestion (see Texas Gulf Coast Bypass Options). This time we consider the impact of the Keystone Gulf Coast pipeline.
One of the more confusing features of the Keystone Gulf Coast Pipeline is what to call it – the name seems to change in real time. That is probably due to a desire to disassociate the southern Gulf Coast section of the pipeline from delays in permitting the Canada to US Keystone XL pipeline. Owner and operator TransCanada most recently set up a subsidiary to operate the pipeline called Marketlink LLC and it should now apparently more properly be called the Cushing Marketlink Pipeline so we will go with CMP as an abbreviation.
The 36-inch-diameter CMP runs 485 miles from Cushing, OK, to Nederland, TX (see green line on the map below). The line will have an initial capacity of 700 Mb/d with the option to expand to 830 Mb/d. It is almost ready to commence operations but before that can happen it has to be filled with oil – a process known as “line fill”. We described how line fill works and provided a formula to approximate the volume of oil required back in May 2012 (see A Time for Gas A Time For Crude – Part 2). According to that formula CMP requires 3.5 MMBbl of line fill. Marketlink LLC has said the first pipeline deliveries will be made before the end of 2013. The company is also constructing a 48-mile Houston Lateral pipeline (orange line on the map) that will run from the Liberty pumping station to East Houston and should be online by the end of 2014 with 130 Mb/d capacity.
Source: TransCanada Website and RBN Energy (Click to Enlarge)
The initial destination of the CMP is the Sunoco Logistics (part of Energy Transfer Partners) Nederland terminal. We have covered the Nederland terminal in two previous blog posts (see Nederland Crude Wonderland and Nederland Crude Volume Surges). The terminal is located on the Sabine-Neches waterway between Beaumont and Port Arthur, TX and has 22 MMBbl of storage capacity (see map below). The location is in the heart of Beaumont/Port Arthur refining country – home to four large refineries owned by ExxonMobil (Beaumont, 365 Mb/d), Valero (Port Arthur, 310 Mb/d), Total (Port Arthur, 174 Mb/d) and Shell/Saudi Aramco (Motiva 600 Mb/d). The Sabine Neches Waterway connects to the Gulf of Mexico, providing waterborne access to the entire Gulf Coast region. Nederland is about 100 miles East of Houston and 350 miles West of New Orleans.
Alaska officials, concerned the state’s once-dominant role in U.S. energy production will continue slipping, are taking a fresh look at helping to jump-start a combined natural gas treatment plant, gas pipeline and LNG export project that would free vast volumes of natural gas now stranded at the state’s North Slope. A new study commissioned by the state found that it could make sense for Alaska to take a 20% or higher equity stake in the project, but that there are significant risks the state would need to mitigate. Today we look at whether the 49th state can make a long-stalled plan by producers to move North Slope gas to market a reality by the mid-2020s.
Alberta has a serious and still-growing problem with stranded natural gas. The volumes of gas piped east and south have been declining and the amount of gas stored in-province has risen to near-record levels, despite a widening discount to US Henry Hub spot gas prices making Alberta gas cheaper than ever. U.S. shale gas is largely to blame, but Alberta gas producers need more than a scapegoat, they need new markets—new ways to either use more of their gas closer to home or move it economically to the east and south or to buyers overseas. It won’t be easy. Today we look at potential new sources of demand.
The Energy East pipeline project proposes to convert part of the TransCanada Mainline natural gas system and add new pipeline in eastern Canada to connect oil receipts in Alberta with refineries in Ontario, Quebec and on the Atlantic seaboard. The proposal competes with existing plans by Enbridge to feed eastern Canadian refineries with light crude but does offer the prospect of supplying heavy crude for export from Canada’s East Coast. Today in Part 2 of a series on the project we review destination markets.
The TransCanada Energy East project proposes converting 1865 miles of the natural gas Mainline system and constructing 870 miles of new pipeline to deliver at least 500 Mb/d of crude oil to eastern Canada from Alberta. The pipeline conversion could solve two problems. It would bump up tariff revenues on the huge 7 Bcf/d Mainline that has been sucking air for years (it only moved 2.4 Bcf/d in 2012). And it would provide a route to Eastern markets for rising production volumes of landlocked Canadian crude. Today in the first of a two part series we examine prospects for this project.
The latest Energy Information Administration (EIA) April 2013 short term energy outlook forecasts US crude oil production to increase from an average of 6.5 MMb/d in 2012 to 7.9 MMb/d in 2014. Surging crude production needs to find routes to market – and often competes for pipeline space with growing Canadian imports. New crude pipelines are taking too long to build. At the same time many natural gas pipelines are flowing far beneath capacity because new gas production nearer to market makes them redundant. Converting these natural gas pipelines to crude oil use where geography allows is a potential win-win. Today we look at gas to crude pipeline conversion economics.