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.
Recap
In Part 1 of this series we outlined the latest crude takeaway project in the Permian Basin – a 540 Mb/d pipeline between Midland and Sealy, TX - announced by Enterprise Product Partners (EPD) at the end of April (see Watching The Defections – Permian). Although the EPD pipeline has signed up shipper support, those shippers are likely to be defectors from existing pipelines, because the incremental capacity does not appear to be justified by forecast production estimates. In Part 2 we turned to the most recent crude takeaway project announced in North Dakota – the TransCanada Uplands pipeline - that will offer at least 220 Mb/d of capacity for Bakken producers to ship crude north of the border to Canada. An interconnect with the TransCanada Energy East pipeline at Moosomin in Saskatchewan will then allow those barrels to flow east to refineries in Eastern Canada and potentially all the way to the Atlantic Seaboard by 2020. Like the EPD Permian project, the proposed TransCanada Upland pipe will add more pipeline takeaway capacity from North Dakota than current production estimates justify. In fact – in the Bakken, most crude is still shipped by rail (although the balance is moving towards pipelines) and when you add rail capacity to the current and planned pipelines – the total is almost double RBN’s “Growth” production scenario by 2020. This time we describe how the Upland pipeline could compete head on with an existing Enbridge project as well as with imports to Eastern Canada coming from the Eagle Ford in South Texas and rail shipments to U.S. East Coast refineries.
Competition With Enbridge in Eastern Canada
The huge Enbridge Mainline system (made up of multiple pipelines) delivers up to 2.5 MMb/d of hydrocarbon liquids (mainly heavy crude from Western Canada) to the US border in Minnesota where the system name changes to Lakehead. At Clearbrook, MN Enbridge Lakehead receives incoming crude from the Enbridge North Dakota system. Once it reaches the Great Lakes at Superior, WI, the Lakehead system winds its way around Lake Michigan in two directions - flowing light crude north on Line 5 direct to Sarnia, Ontario but the majority of its payload south along two routes – one through Chicago that mostly feeds refineries in the Windy City and the other further west to Flanagan, IL. The Flanagan terminal in Pontiac, IL is the central pivot point in the Enbridge US system with crude flowing from there either north and east through Illinois to Griffith, IN and then back into Canada at Sarnia or southwest to Cushing, OK.
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Comments
Not sure your statement that movements from the terminus of Energy East into the US will not require Jones Act ships. The crude may move in bond and therefore title never transfers to Canada and Saint John will likely be a US port for purpose of such movements for US sourced crude. However Canadian crude such as syncrude, conventional light, dilbt and Canadian tight oil would all move to the US without Jones Act ships. Check with somebody who understands the rules around shipping through Portland Maine to Canada, believe for Canadian crude such as Hibernia a Canadian flag is required even though the movement is coming through the US, I expect the Jones Act would work the same way as the Canadian domestic shipping requirements.
In reply to Jones Act by Ross Belot
Good point. Will check into that.
Hello Rbners, I used to put my comments on RBN 1-2 years ago, my engagements do not always allowed me to comment but think I will do a little something. I still feel that RBN in today's level energy data
playing field is the best on energy economics maybe because the people behind it take more risks than the average analyst ?!
Sarnia would be just a little farther south on the map! (But as a New Brunswicker could I locate myself refineries in Galveston Bay !
My cue is that Bakken will not go to SJ by Energy East.For Enbridge, I am not too sure; logic would be no heavy in Sarnia, MTL without Cokers. meaning Billies in investments. AActually Line 9 is operational up to Nanticoke (Esso) with U.S crude, currently filling the lines we will have an idea in July (for Montreal), The potential for exports is quite limited and I am not too sure how Enbridge will canibalize Railed Crude for until many years, it's only 240,000 Bpd from Sarnia.Bakken Batches will continue to flow by rail or tanker to SJ. (Read Tankers from Texas by Poten, the New York firm and no.1 very dominant tanker/energy broker in the world). Irving will play them against foreign equivalents.
Watch out this is the hot stuff:
-Energy East will bring Heavy that will be desulphurized to be burn locally in SJ /or shipped into the USGC/NY harbor Blending pool...
-There is an environmental arbitrage possible between Can/New England for Irving/Transcan when they burn the fuel oil here (also concerning your previous post Please Come To Boston—New England’s Ongoing Gas-Supply Dilemma).
FYI Belro19, no U.S fuels flow into Montreal-Maine Pipeline and no Foreign Flag Vessels deliver U.S oil to Portland...
This asset is underused (only barely less than 80K/d) for Foreign Crudes because of the Brent/WTI economics.
Could it make senses for Enbridge to buy-out the line, reverse it, and connect it to Line-9, possibly with Light (bakken) delivered to the USAC by JA tankers...
Problem is that Commodity Wall Streeters easily walk away from deals not based on a transactional approach such connecting a pipe to no refineries at the other end... That's why Irving Oil matters for Trans-Canada.
ALSO message to the "Wichita co. brothers" Heritage Foundation friends: I feel that these comparisons of Jones Act in the medias with foreign units are skewed, Jones Act (JA) always made to look more unfavorable than it should.
Sometimes Economists hired by thinktank compare different sizes of vessels which yield radically different $/Bbl. i.e don't compare a JA 330,000 bbls capacity unit with a 1,000,000 bbls capacity on the Foreign Flag Market...They also never say that few/no vessel are available in U.S Fleet, Jones Act is all about the SUPPLY AND DEMAND, spot voyage are just more expansive like in any markets with price TAKERs.Because RBNers love $/BBL here is a sneaky look into Houston/ Marcus Hook Voyage based on the current Jones Act Market on a realistic tanker size used by Refiners.
The Suezmax Case
Cost
JA Suezmax
$/bbl
1.28*
$/bbl
2.11**
$/bbl
4.22***
*2 RV/month* on a JA newbuilt Suezmax 10 years charter= $1.28/bbl (assuming API 40, 991,000 bbls cargo, 15/13kts, 6d laden, 6 days ballast, 2 days loading, 1 day disch., +5% sea/weather margin)
...
T/A Suezmax Spot Voyage costs more than in the $4/bbl these days and can also hit the double in the very volatile international oil freight market.
People who think that Jones Act can't perform will hit a wall soon. Voyage costs of carrying WCS into JA tankers by Energy East via SJ to USGC and haul-back the Eagle ford, just fantastic for the Irvings.
And even in the Clean Product Market, the Jones ACT is often "in-the-money" creating Arbitrages because of what the gasoline/diesel traders "do" on Colonial but never reported in the Platts, Argus or anywhere in the energy press...
These were some ideas that I wanted to pitch, I'd like to write my collum on RBN more often, maybe injecting of a dose of Maple Syrup into the Texas Splitter.
You might read Simon in the Daily Energy Post if I might be invited in the future as a guess writer to comment the U.S-Canadian Energy Trade in relation with the Energy Freight Market :)
Simon Jacques, Commodity Transportation Specialist
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