Most Interesting Development -- March 6, 2020

Updates

April 14, 2020: as scheduled, the PSC was scheduled to consider this pipeline request today, The Bismarck Tribune link here.


Later, 2:39 p.m. Central Time: an eagle-eyed reader caught this one. Look at the story below.

• Time line:
• story published today by The Williston Herald 
• pipeline to be operational by April 1, 2020
• PSC hearing two weeks later: April 14, 2020
• time to construct: 6 - 8 weeks
• Comments:
• either a typographical error, and more likely to be operational by July 1, 2020; or, 
• "they" have the ditch dug, pipe in place; just waiting for the go-ahead?  

Or someone's watching too many re-runs of "Back To The Future."
 

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Original Post

Link here.

As the amount of Bakken gas production has increased, future BTU limits on the Northern Border pipeline have become more and more likely. That’s prompting a unique proposal for an alternative, high-BTU gas market in the Williams-Mountrail County region.

Liberty Midstream Solutions is proposing a 4.7 mile, 8-inch residue pipeline on privately owned lands in the area to take high-BTU residuals to an existing third-party line, from where it could be sent to markets in Chicago.

The Alliance Sales Line would carry up to 80 million cubic feet per day for an estimated construction cost of $4.6 million.

The Public Service Commission has set a public hearing for the pipeline at 9 a.m. April 14 at Neset Consulting Service in Tioga. The company has asked for waivers of some procedures and timelines to expedite construction.

Liberty hopes to have the line operational by April 1, 2020. It would take six to eight weeks to construct.

Much, much more at the link. Archived.

Maps:

Is The Bakken Heading Toward A Crude Oil Pipeline Overbuild? -- RBN Energy -- July 29, 2019

How desperate is China for more oil? China still taking Iranian oil despite tougher US sanctions. In addition, I bet China is getting a great deal -- a steal, some would say -- from Iran.

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Pipeline Negotiations in Mexico

Updates

August 27, 2019: Reuters is reporting that issues between Mexico and US pipeline companies have been resolved. 

Original Post

 

Mexico: Rigzone has a nice little update. Things do not look good. This has huge implications for the "southern surge," something we've discussed before. This is most concerning at so many levels, not just for investors (in the note below, CFE is the state utility -- think a nationalized Con Ed on steroids):

Although now the go-to fuel for power and industry, there is simply no national gas strategy in Mexico. Instead, the focus of the AMLO administration is on new crude oil production and refineries – both too expensive for Pemex, already over $100 billion in debt. In addition, supported by AMLO, CFE has been using arbitration hearings to try and nullify terms for 25-year contracts in natural gas transportation. The argument is that CFE should not have to make capacity payments for delayed pipelines not yet operating.

Even when a start-up date is announced, there is just too much uncertainty. For example, TransCanada and IEnova’s 2.6 Bcf/d undersea Sur de Texas-Tuxpan, running 480 miles from Brownsville, Texas, to Tuxpan, Veracruz state in southeastern Mexico, should already be in operation. But just on July 3, CFE blocked the start of commercial gas flows until the transport contract that anchored construction is renegotiated. All of this is obviously giving even more pause to potential investors and pushing a mature Mexican gas market farther out of reach.

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Mexico Refinery

Mexico: from Bloomberg, the refinery. I believe this was posted previously but it's still important enough to post again, just in case.

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Back to the Bakken

No wells came off the confidential list this past weekend and none are scheduled to come off today. This is the longest stretch I have seen of no wells coming off the confidential list. We wll see new wells tomorrow, however.

Active rigs:

$56.21	7/29/2019	07/29/2018	07/29/2017	07/29/2016	07/29/2015
Active Rigs	58	62	61	35	73

RBN Energy: is the Bakken heading towards a crude oil pipeline overbuild? Part 2. Archived.

Bakken crude oil production surpassed 1.4 MMb/d this spring and has maintained a level near that since, even posting a new high just shy of 1.5 MMb/d in April 2019. The rising production volumes have filled any remaining space on the Dakota Access Pipeline (DAPL) and prompted midstream companies to step up expansion efforts to alleviate the pressure, even as questions linger about the possibility of a pipeline overbuild if all of the announced capacity gets built. Specifically, the market is weighing the need for the recently announced Liberty Pipeline and a DAPL expansion. Today, we look at these two new projects and what their development means for the supply/demand balance in one of the U.S.’s biggest shale basins.

What we do know is that until new pipeline capacity out of the Bakken comes online, there will be more and more Bakken barrels that won’t find a home on existing pipeline systems. Based on our forecast growth, there could be up to 200 Mb/d of stranded crude that needs to move via rail out of the Bakken heading into early 2020, before either Liberty or a DAPL expansion gets completed. And as more barrels transition from pipeline pricing to rail pricing, Bakken differentials could widen as well, moving in tandem with the higher cost to transport crude via rail.

Takeaway Capacity In The Bakken -- Forbes -- October 13, 2018

Re-posting. Not sure if I posted this last March, 2018. From Forbes, "time to concede the Bakken bear call?" The only problem with the headline? The question mark.

With the DAPL still in question (in the hands of the Iowa Supreme Court -- I assume the decision will be announced NLT than mid-November), it is time to look once again at Bakken takeaway capacity.

In the graphic above, the legend runs from "refinery demand" at the bottom, to DAPL (purple) and truck/rail (CBR - light blue/striped) at the top.

Note that the x-axis runs out to 1Q21 or thereabouts.

Update Regarding North Dakota DUCs -- June 29, 2018

Disclaimer: in a long note like this and with so many numbers, and no triple-checking and no NYT fact-checker, there will be factual and typographical errors.

Updates

July 2, 2018: with regard to DUCs, my thesis is that shale operators are using DUCs to manage their assets. Someone suggested the reason there are so many DUCs is because of limited takeaway capacity. I was thinking the same thing. Then I read this from last week (the article is a keeper; it's been archived).

“The indicator that I typically watch, the Brent Oil price minus the WTI price, that spread was just over $10,” Kringstad said. “When that price is higher than $5 per barrel, historically the industry tends to pull barrels off the pipeline systems and put them on the rail network to take advantage of that market situation.”

CBR: scalable.

Number to remember: any number higher than $5, Brent/WTI spread. If Brent is $10 higher than WTI, then it makes sense to send Bakken oil to east coast where they buy Brent, instead of to Cushing where they buy WTI.

And more from the article:

Rail transport hit a low last summer of around 120,000 barrels per day, Kringstad said, but was back up to 260,000 barrels per day in March as market conditions shifted to favor east and west coast crude by rail markets. 

Some of that shift is a result of oversupply in Cushing, Oklahoma, Kringstad said. Permian oil is congesting that market hub, lowering prices. Oil that can go to east and west coast refineries is thus finding better prices there.

Pipeline capacity, though pushing the upper limits, is still adequate (barely?):

Long-term forecasts for North Dakota oil production by the mid-2030s is for between 2 and 2.4 million barrels of oil per day, about double of what it is now, Kringstad said.

“When we look at the takeaway capacity options, it’s right around 1.4 million bpd with what is now in service or slated to come online in the next several years, so there is potentially a 600,000 to one million barrel per day potential shortfall long term,” he said.

Original Post

Update regarding DUCs.

Bottom lines:

• Bakken wells are most productive after initial frack (and possibly after subsequent fracks); completing one or two more DUCs in any given month can literally mean the difference between setting a new month-over-month production record and not setting a record
• there was a temporary increase in the number of DUCs during the Saudi Surge (2015 - 2016)
• considering the price of oil over the past three months, I consider the number of DUCs (now over 900) to be more than expected
• I know there are folks who disagree with me
• there are articles in the mainstream press suggesting ND is simply working down the backlog that occurred during the Saudi Surge; this may be the best article (a Bloomberg article) suggesting ND is "working down that backlog"
• the second and third graphs below do not support that argument (although that's in the eyes of the beholder)
• if ND was "working down the backlog" it does not explain the upward trend for the past three months
• anecdotally, recently there has been a long stretch in which none to few DUCs have been reported as completed 
• most analysts I have come across, who are much, much more knowledgeable than I am, do not consider DUCs to be an issue worth spending much time on

Bottom, bottom line: with regard to DUCs, there's something going on that isn't explained in the data. Time will tell. As it always does.

Note: the number of DUCs (drilled to depth but waiting for completion) and inactive well numbers (AB and IA) are all estimates, although the number of DUCs should be a fairly accurate number. In addition, it depends on the exact day that the data is collected.

I will post graphics first to bring us up to 2016 or so. These graphics were taken from various sources using a google search.

First, these three graphics.

From January, 2014 -August, 2015:

• range: slightly below 600 to a high of just under a 1,000; trend was moving up through all of 2015; this was during the Saudi Surge; the trillion-dollar mistake Saudi made trying to break the US shale operators

From January, 2014 - October 16, an overlap with above data, but takes us to October, 2016:

• it makes no sense to me why EIA numbers are lower than NDIC numbers, when the former includes Montana and North Dakota, whereas the latter includes just North Dakota
• range: slightly below 600 on a couple of occasions in 2014, before the Saudi Surge; to a high of almost 1,100; trend was moving up through all of 2015; this was during the Saudi Surge; the trillion-dollar mistake Saudi made trying to break the US shale operators; after September, 2015, there was a slight but definite downward trend, to about 900 in August, 2016

From December, 2016 - April, 2017, an overlap with above data, but takes us to April, 2017:

• December, 2016: 790
• April, 2017: 821

From most recent data, May, 2018 - May, 2017, most recent to oldest, which brings us up to date:

• taken from my posts on the blog. In May, 2017, I started posting DUCs and inactive wells on a regular basis. It's too time consuming to go back and fill in the few months in which I did not post data so I'm not going to fill in that bit of missing data. I think the existing data tells the story. 
• data below: month/year, DUCs, inactive wells. All data below, including the up/down change were taken directly from the NDIC Director's Cuts
• range:
• an outlier, March, 2017: 689
• otherwise, a low of 799 in February, 2017
• a high of 955 in the most recent month, May, 2018
• not graphed, but the trend for the past four months has been up 
• up 48 in February, 2018, 901
• up 15 in March, 2018, 916
• up 26 in April, 2018, 942 
• up 13 in May, 2018, 955

Inactive wells:

• in data presented, we have never gone above 1,700 inactive wells
• number of inactive wells in the past three months are among the highest numbers in the data presented

The raw data:

September, 2018: 928, up 3 from previous report
inactive: 1,340, down 87

August, 2018: 925, down 18 from previous report
inactive: 1,427, down 59

July, 2018: 943, down 50 from previous report
inactive: 1,486, up 28

June, 2018: 993, up 38 from previous report
inactive: 1,458, down 111

May, 2018: 955, up 13 from previous report
inactive: 1,569, down 48

April, 2018: 942, up 26 from previous report
inactive: 1,521, down 132

March, 2018: 916, up 15
inactive: 1,653, down 1

February, 2018: 901, up 48
inactive: 1,654, down 100

January, 2018: 853, down 24
inactive: 1,554, up 85

December, 2017: 877, down 6
inactive: 1,469, down 23

November, 2017:

October, 2017:

September, 2017: 853, down 10
inactive: 1,444, down 54

August, 2017: 863, down 26
inactive: 1,498, up 20

July, 2017: 889, up 34
inactive: 1,478

June, 2017: 865, up 35
inactive: 1,458, down 53

May, 2017: 830, unchanged
inactive: 1,511, up 45

April, 2017: 830, up 141
inactive, 1,466, up 167

March, 2017: 689, down 110
inactive: 1,299, down 312 (need to correct typo at that post)

February, 2017: 799, down 3
inactive: 1,611, down 67

January, 2017: 802, down 5
inactive: 1,678, up 105

December, 2017: 807, down 32

November, 2017: 839, down 21
inactive: 1,519, up 16

October, 2017: 860, unchanged
inactive: 1,500 (unchanged (AB and IA)

September, 2017:

August, 2017: 888, down 24
inactive: 1,514, up 44

July, 2017: 912, up 25
inactive: 1,486, down 98

June, 2017: 887
inactive: 1,584

May, 2017: 931, up 39
inactive: 1,584, down 6

Disclaimer: in a long note like this and with so many numbers, and no triple-checking and no NYT fact-checker, there will be factual and typographical errors.

Permian Operators Facing Huge Challenges -- April 18, 2018

WTI is surging (?) -- it might hit $70 this week. But a reminder, from RBN Energy:

Price differentials in the Permian Basin are widening at a rapid pace.

The discount for Midland crude to West Texas Intermediate (WTI) at Cushing has widened by over $4/bbl since the beginning of March and the discount to Magellan East Houston (MEH) crude was over $7/bbl yesterday (April 3, 2018).

Permian production is increasing at a breakneck pace as new players are entering the scene. Private equity-backed exploration and production companies (E&Ps) are no longer just acquiring and flipping acreage, as they are being forced to prove their assets are profitable and can generate a return on investment.

The combination of large drilling plans from the majors and new production from these smaller operators — with no new pipeline takeaway capacity in sight — has sent Permian crude pricing into a tailspin. Today, we begin a new series on the recent slide in Permian prices, how new producer strategies are contributing to it, and what it means for pipeline space, trucking and midstream infrastructure.

We saw the same thing in the Bakken during the boom.

Remember: a lot of the operators paid a huge amount of money to get into the Permian.

From Platts this week:

Pipeline capacity is currently constrained out of the Permian, reflected in wide price discounts for Midland WTI crude. Midland WTI is averaging at a $4.33/b discount to Cushing WTI so far in April, compared to a 93 cents/b premium in January, S&P Global Platts data shows.

WTI Midland moved higher on the news of additional takeaway capacity Monday. WTI Midland was assessed at a $3.70/b discount to Cushing WTI, up 35 cents/b on the day.

S&P Global Platts Analytics is projecting crude oil output in the Permian to reach 5.266 million b/d by 2020, compared with 3.657 million b/d in 2018.

If Permian goes to "5," the Bakken goes to "2."

CBR Ending For US East Coast Refiners -- April 21, 2017

DAPL is flowing.

Largest refiner on US east coast will no longer take rail deliveries of Bakken oil.

Good, bad, or indifferent with regard to one's thoughts about pipelines, think about  it: 425,000 bopd that used to be by rail through Minneapolis, Chicago, etc., will no longer go through those cities. 

Reuters story with data points:

• largest refiner on US east coast: Philadelphia Energy Solutions Inc
• at its peak, took three miles' worth of trains filled with Bakken oil each day
• just five rail deliveries in May; no rail deliveries in June 
• recently getting one unit train per day; one unit train: 75,000 bopd
• rail volumes in the Bakken peaked at 420,000 bopd
• DAPL begins interstate crude oil delivery May 14, 2017
• 1,172-miles long
• western North Dakota to Patoka, IL
• 450,000 bopd
• will connect to large refineries in the Nederland and Port Arthur, TX, area

Update: Bakken Pipeline Takeaway Capacity -- April 1, 2017

Early on, I had a lot of posts regarding "takeaway capacity" in the Bakken. I haven't looked at that in a long time. Here is a link to a Oil & Gas Finanacial Journal story from late last year that brings us up to date: Bakken Piepline Takeaway Capacity.

Archived.

Railroad Takeaway Capacity in the Bakken -- One Word: Amazing

Link to InsideClimate News/Dickinson Press.

Datapoints:

• rail capacity in the Bakken: up 55 percent in June with addition of two new loading facilities
• Dore: jump from 10,000 to 60,000 bopd (Musket Corp)
• Rangeland/Epping: 120,000 bopd
• 17 rail/oil terminals built since 2008
• current rail/oil capacity: 470,000 bopd
• possibly could reach 710,000 bopd by end of the year

Folks may want to reflect on this. I suggested that producers may be choking back on their productivity if there is a lack of takeaway capacity. As takeaway capacity is increased, production should increase. I mentioned that to someone, and his immediate response was that production will increase when the price of oil gets back to $100.

I think we will be quite surprised a year from now with production numbers coming out of the Bakken.

Pipeline Activity in the Oil Patch -- Current Trends -- The Bakken, North Dakota, USA

Link here to an absolutely excellent article. Simply one of the best articles this week (year?).

In the winter of 2012 a mostly snowless and relatively warm Bakken Shale play in northwest North Dakota was trucking about 70% of its oil supplies in the gathering and processing phase as production continued at an all-time record clip averaging 546,000 bpd in January. New midstream infrastructure construction was limited to intrastate shipments within an under-developed gathering and processing system.

In various ways this scenario is being repeated in many of the shale plays as production of oil, natural gas liquids and gas continues to outpace the development of midstream infrastructure. As a result, many of the exploration and production (E&P) operators are increasingly getting involved in takeaway infrastructure.

“I think there is a trend, although you will probably get different philosophies on the subject,” said David Lundberg, a New York City-based analyst with Standard & Poor’s Ratings Services (S&P). “It is particularly evident in certain shale plays where the infrastructure is not well built out, such as the Bakken.” 

The data points are endless in this long (4-page) article. 

EIA Update on Takeaway Capacity in the Williston Basin

"M4570D0N" provided this:

The EIA came out with a new report on Tues (4/17):
"Williston Basin Crude Oil Production and Takeaway Capacity Are Increasing"
http://www.eia.gov/todayinenergy/detail.cfm?id=5870

At the link:

Crude oil production from the Williston Basin (primarily the Bakken formation) recently increased to more than 600 thousand barrels per day (bbl/d), according to Bentek Energy, LLC (Bentek), testing the ability of the transportation system—oil pipelines, truck deliveries, and rail—to move crude oil out of the area (see chart above). The current price gap between Bakken crude oil and West Texas Intermediate (WTI) shows the effects of this constraint. Bentek projects more transportation capacity coming online in 2012, potentially alleviating this constraint. 

Takeaway Capacity in the Bakken: An Update and Overview

Link here to RBN Energy  (registration may be required).

Takeaway Capacity Still A Challenge for the Bakken

Looking back on all the talk during the past two years about adequate takeaway capacity in the Bakken appears, in hindsight, to have been a huge misreading by everyone, not least of which was NDIC. I blogged often that NDIC said there would be adequate takeaway capacity. That is clearly not the case and is costing mineral owners (and operators) a huge amount of money.

Outside interests are concerned about profits going up in flames (flaring) when, in fact, that's the least of the mineral owners' issues. If there is one factor  that is costing mineral owners monthly income, it would be related to the lack of takeaway capacity. Flaring is a non-issue.

And now there is yet another story reminding us that takeaway capacity will continue to be a problem in the Bakken. Link here to Rigzone.com.

US tight oil producers already face challenges in economically getting their high-quality crude to refineries, and transportation logistics will need to be addressed more fully as production grows, experts at an Apr. 3 Washington conference agreed.

Some Bakken shale producers already ship their crude by rail to Louisiana to get a price closer to North Sea Brent than to West Texas Intermediate, Hill Vaden, a senior US upstream research analyst at Wood Mackenzie Ltd., told the conference cosponsored by the US Association for Energy Economics National Capital Area Chapter and the Center for Strategic and International Studies.

I suggested a way to address the problem but ....

Trends -- The Impact of the Bakken -- Further Impact of the President Killing the Keystone

Link here.

And more here.

This is really quite incredible -- the impact of four counties (Williams, Mountrail, McKenzie, and Dunn) in fly-over country.

Unless I'm reading one of the linked stories incorrectly, it looks like Valero won't be adding another coker in Louisiana because of the UNCERTAINTY of the KEYSTONE XL. The CEO is not convinced that the pipeline will be finished any time soon, obviously.

Every day, the decision to kill the Keystone XL 1.0 looks more and more irresponsible and ill-conceived.

Meanwhile, purging of the Seaway is complete, one more step in process of reversing the flow.

Back to the earlier links.

First, the  impact on the Bakken leading to increased sweet oil imports in the Gulf:

Increasing U.S. onshore shale oil output likely will displace light sweetcrude imports to the U.S. Gulf Coast by 2015, Valero Corp Chief Executive Bill Klesse said on Tuesday. The increased sweet crude going to Gulf Coast refineries also is expected to narrow heavy crude differentials to thepoint that Valero aims to shelve plans to add a coker unit toits 292,000 barrel-per-day refinery in Port Arthur, Texas,because it won't be economical, Klesse said.

Four years ago we thought we want to build cokers to do allof this but today you're seeing much more light sweet crude,"said Klesse, head of the largest U.S. independent refiner,during a break at the annual meeting of the American Fuel and Petrochemical Manufacturers in San Diego, California.

"In another two to three years, we are saying like 2014 to 2015, there will be no light sweet crude imports into the U.S. Gulf Coast. It's about a million barrels today," he said.

In North Dakota alone, drilling in the Bakken shale prospectdoubled the state's crude output in the last two years to546,050 barrels per day (bpd). That will narrow the discount of heavy crude compared tolight, so much so that Valero expects to let its permit for a $500 million coker project at the Port Arthur plant expire.He said a big factor in the equation is uncertainty as to when TransCanada's proposed $7 billion Keystone XLpipeline can move forward to transport Canadian heavy crude from Alberta to U.S. Gulf Coast refineries with coker capability to process it -- like several of Valero's plants. 

Pressure on Canadian oil sands and  Bakken sweet:

Bargain-basement discounts on Canadian crude are more than just a short-term irritant for producers as surging supplies and a limited U.S. Midwest refining market threaten to cut
industry-wide revenues by as much C$18 billion ($18 billion) a year, an analyst said on Monday.

Wide light and heavy crude price spreads plaguing the Canadian market since the start of the year could expand even more in the coming two months as numerous refineries begin
maintenance, and the end of that work and start of a reversed pipeline to Texas from Oklahoma won't bring permanent relief to fundamental problems.

He said the situation could last beyond 2013, when the Keystone XL southern portion starts to drain large volumes of>supply from the Cushing, Oklahoma, storage hub and moves it toTexas refineries. The northern, cross-border portion of Keystone XL and or newpipeline capacity to Canada's West Coast are not expected tostart up until the second half of the decade.Another factor that may ease the situation could be a reversal of Royal Dutch Shell's 1.2 million barrel a day Capline pipeline to Illinois from the Gulf Coast, Potter said.

One source told Reuters on Monday that the concept i sunder discussion.

Canadian synthetic crude, derived from the Alberta oil sands, and Bakken light oil, from North Dakota shale deposits, are selling for around $16 a barrel and more under U.S. benchmark West Texas Intermediate crude and $34 under the international Brent marker.

Some great investment opportunities, if one thinks about it.

Takeaway Capacity -- WLL Presentation -- February, 2012-- The Williston Basin, North Dakota, USA

April 9, 2012: ONEOK announces the 1,300-mile Bakken Crude Express Pipeline from Stanley, North Dakota, vicinity, to Cushing, Oklahoma. [Update: the Bakken Crude Express Pipeline was canceled by ONEOK; not enough subscribers.]


-->

Updates Original Post Pipeline	Existing	2011 Add	2012 Add	2013 Add	Total
Enbridge	185K	25K	145K		355K
Bridger/Belle Fourche	120K	30K	50K	100K	300K
Tesoro/Mandan	60K				60K
EOG (rail)	60K				60K
Plains			50K		50K
Hess (rail)			60K		60K
COLT (rail)			60K		60K
BOE (Lario)(rail)		100K	100K		200K
Savage (rail)			90K		90K
Quintana (rail)				90K	90K
Total	425K	155K	522K	190K	1,292K

So, today with rail, about 580,000 bbls takeaway capacity. Some of these lines accept Bakken oil only, such as Enbridge.

According to the slide from which I got this information, the Keystone pipeline goes through western North Dakota but has no connections to any pipeline inside the state. 

I understand that Enbridge is adding rail capacity. I do not know if Enbridge rail capacity is included in the figures above. I doubt it.

The above figures do not include the languishing Keystone XL which would go through western North Dakota, but certainly not earlier than 2013.

The "big" Enbridge pipeline takes Bakken crude to Clearbrook, Minnesota.

The Bridger/Belle Fourche is a huge pipeline, south from Tioga/Ray area, passes Dickinson on the west, and then angles southwest into Montana at the ND/SD line.

The Quintana is a north-south pipeline, also, running passing Williston on the west, passing Dickinson the west (going through Whiting's Lewis & Clark prospect) and then angles southwest paralleling the Bridger/Belle Fourch. [The slide shows it as "rail" but I think it's a pipeline: Quintana Capital Group Pipeline: In June 2010, Quintana Capital Group announced plans to connect the major producing regions of the Williston Basin with TransCanada’s Keystone XL pipeline in Eastern Montana. The proposed $250 million project would have an initial capacity of 100,000 bpd and could be expanded to 120,000 bpd. The plans utilize 310 miles of new pipeline and would connect the heart of the Bakken play with the Keystone XL pipeline near Baker, MT in early 2013.]

By the way, speaking of "takeaway," here's a commercial for a double-breasted chicken sandwich:


Only in Australia

Takeaway Capacity -- Bakken, North Dakota, USA

This is an interesting story, about Hess and the oil-loading facility at Tioga.

Alan Fuller, operations manager of the Hess crude-by-rail facility west of Tioga, reported that construction continues and until the pipeline and the automated features are complete in December, transloading from trucks onto railway cars will be conducted.

Beginning Oct. 17, 40 to 45 trucks a day will be traveling north from US 2, up Co. Road 21 to the facility, where the oil will be loaded onto railway cars.  

It's a regional link that will break early so if you want to read it, you may want to read it sooner than later.

I would assume that most folks will simply read this as another unremarkable story, just another story in the Bakken. And maybe it is.

But, I am hearing that Enbridge (pipelines) and the crude-by-rail folks have been hit with increasing requests: it's just a rumor, mostly just an idle comment from someone standing in line for coffee, but when you hear that comment and then read this story, it really does suggest that all those stories from state officials and corporate presentations about adequate takeaway capacity suggest that production and takeaway capacity is more finely balanced that I was led to believe a few months ago.

Then add the statement by Lynn Helms a couple days ago: North Dakota produced about 400,000 bopd in August, which is already quite remarkable, close to Alaska's and California's 550,000 bopd (each state), and then Lynn Helms said this a couple days ago: North Dakota could be producing as much as 800,000 bopd by the end of the year. That's two months from now but for reporting purposes, we won't know until February, 2012.

Update of the Bakken Pipeline Situation -- North Dakota, USA

Link here (regional link will break soon).

Personalities:

• Kesley Myhre, Enbridge spokesperson
• Justin Kringstad, Director, North Dakota Pipeline Authority

North Dakota Pipeline Authority, mission:

The North Dakota Pipeline Authority works with the companies to help them understand the oil play, as well as offer support through the state and federal government. The North Dakota Pipeline Authority is a state agency that started in 2007.

Current status: three major options for pipelines in the Bakken

• Enbridge system: 210,000 bbls/day
• Tesoro pipeline: 58,000 bbls/day 
• Butte Pipeline: 118,000 bbls from eastern Montana to Wyoming

Currently, maybe 60,000 to 70,000 bopd transported by rail

Four additional projects being proposed or underway:

• TransCanada Bakken MarketLine: expected to start mid- to late-2013; 100,000 bopd from Williston Basin to major hubs in Oklahoma and Texas
• True Company 'Baker 300': 118,000 bopd now; by the end of 2011, that oil flow will increase to 150,000 bopd; and in 2012, increase to 200,000 bopd
• Plains Bakken: will ship up to 75,000 bopd from western North Dakota (100 miles from Trenton) to an existing pipeline along the Canadian and Montana border
• Enbridge Bakken Expansion Program: currently shipping 210,000 bopd; by the end of 2013, the company expects to add another 120,000 bopd capacity

Enbridge projects under construction:

• The Beaver Lodge Loop project: loop an existing pipeline or place another pipeline adjacent ot existing pipeline system; from Enbridge's Beaver Lodge Station through Stanley to Berthold Station
• The Bakken Expansion Project: replace 11 miles of a newly reactivated pipeline, from Berthold to the Canadian border; a new pump station at Lignite, ND, and a new pump station at Kenaston, ND; cost o the US side is $370 million; the expansion work on the Canadian side is $190 million

North Dakota's Oil Transportation Infrastructure -- North Dakota, USA

This link will download a PDF of the December, 2010, North Dakota Pipeline Authority summary of North Dakota's Oil Transportation Infrastructure.

As noted by "Bri-VA" these projections were based on 120 and 150 rigs. Currently there are 167 active rigs (high) in North Dakota. See 2nd comment.

I will post the link in the "Data Links" tab above.

Note: it is projected that North Dakota will produce 500,000 bbls/day by September this year (2011).

[Note: one day after posting, the Williston Herald posts a story that Enbridge will be putting in two short segments (26-mile and 29-mile segments) that will increase capacity by 145,000 bopd in the region.]

Thoughts on Takeaway Capacity -- Bakken, North Dakota, USA

In the December, 2010, NDIC Director's Cut, it is reported that takeaway capacity continues to exceed productivity.

Hmmm.

Other data points from the same report:

75 percent of oil production is trucked from the pad
The amount of oil being shipped by train is increasing
The amount of oil being trucked to Canada is decreasing
Excessive flaring continues to be a problem
Daily production in November was impacted by snowstorms (trucks can't get to sites in inclement weather)

What does that suggest to me?

Takeaway capacity exceeds production only because production is impacted by infrastructure choke points, weather and the railroads' ability to scale up.

The two data points we don't have:

To what extent (in bbls/day) does takeaway capacity exceed production?
To what extent can railroads scale up? (physically and economically)

75 percent of productivity is impacted when trucks can't get to the site. But is inclement weather the only thing keeping trucks getting to the sites? Are there adequate number of trucks, adequate number of drivers on a daily basis to meet demand? How often are pumps turned off when on-site tanks are filled and trucks don't arrive on time?

By law / regulation, operators are not allowed to maximize oil production when natural gas is still being flared. Operators are putting in natural gas pipelines, it seems, as fast as they can to "get rid" of this problem. It's, of course, exacerbated by the fact that natural gas prices aren't all that great. So, if there's natural gas being flared at a site, you can bet that oil production is being choked back. Periodically on the monthly NDIC dockets you will see industry requests to waive the natural gas flaring rule.

With regard to price, I think it's becoming a wash whether rail or pipeline is better. Refineries pay less for North Dakota oil when it arrives by pipeline because it is mixed with less desirable heavy oil from Canada; refineries pay more for "pure" Bakken oil when it is shipped by rail, but it costs the producer more to ship it by rail.

For an individual mineral rights owner, the fact that he/she is not taking a loss on Bakken oil due to lack of takeaway capacity is good news.

But for the industry and for the state of North Dakota, having excess capacity is not good news. It highlights the fact that overall production is being held back, mostly due to lack of pipeline (oil and natural gas) infrastructure.

At least that's how I read it.