Monday, June 17, 2019


Brigham (BEXP) --> Statoil (STO) --> Equinor (EQNR)
  • February 10, 2021: to exit the Bakken, 242,000 net acres, $900 million;
  • August 28, 2020: to stop drilling in the Bakken.
  • June 17, 2019: Equinor US inventory
    • Marcellus: 247,000 net acres
    • Eagle Ford: 69,000 net acres
    • Bakken: 235,000 net acres 
  • March, 2018: will change name from Statoil to Equinor
  • November, 2012: NOG says 375,800 acres
  • December 9, 2011: noted that ticker symbol BEXP no longer existed 
  • December 8, 2011: Statoil's offer to buy tendered BEXP shares has closed this date
  • October 17, 2011: sale to Statoil announced; effective, 2012
  • August 9, 2011, corporate presentation: 375,800 net acres;
  • June 7, 2011, corporate presentation: 378,100 net acres; 6,900 additional acres
  • 1Q11 conference call: 371,200 net acres; 6,900 additional acres since last update 
  • Last update: net present value (NPV)/well ~ $9.5 million 
  • 2Q12: rigs, 10 ---> 16 since acquiring BEXP
  • Accelerating to 12 rigs by March, 2012; two dedicated frac teams now
  • (Eastern Montana: Rough Rider and Sedlacek)
  • Rough Rider, 155,100 net acres: Williston area, both north and south of the river; Williams and McKenzie
  • Sedlacek, 9,900 net acres: eastern Montana
  • Parshall/Ross: Mountrail County; most prolific area to date in ND Bakken; 35,900 net acres in the Bakken; 35,000 net acres in the Three Forks (same surface, no doubt)
  • Parshall/Austin/Sanish: 5,300 net acres in the Bakken; 2,700 net acres in TF (same surface, no doubt)
  • Mercer (North Dakota): 30,000 net acres Bakken; 30,000 net acres TF (same surface, no doubt)
  • Other extensional areas: 24,700 net acres

Random Comment On US Natural Gas Inventories -- June 17, 2019

A reader shows us again how incredible the natural gas "fill rate" has been so far this year. See this post for background.

How fast is the natural gas fill rate this year? Really fast.

For the week ending March 22, 2019 -- just a few weeks ago, US natural gas inventories were 20% below inventories one year earlier.

By June 7, 2019, most recent data available, US natural gas inventories are now 10% above those of last year.

There's a reason President Trump is unhappy with Europe linking with Russia for natural gas (Nord Stream 2). The US needs markets for all the natural gas it is producing.

Oasis Petroleum -- May, 2019 -- Corporate Presentation

Oasis Petroleum website here.

  • net acres
    • Bakken: 414,000
    • Delaware: 23,000
Rigs (2019): Bakken, 2 - 3; Delaware: 2
Production, 1Q19: Bakken, 86,000 boepd; Delaware, 6,000 boepd
  • since 2010, over 1,000 wells averaging ~ 10,000 feet of lateral length
  • rapidly applying Williston learnings in Delaware
    • cycle times down by 15 days
    • well costs down from $11.5 million to $10.1 million
Free cash flow: expected to deliver free cash flow at $50 WTI
  • Williston asset producing free cash flow to fund Delaware and OMP growth
  • 1,385 top-tier operated locations
  • 20+ year inventory life at current rig pace
  • top tier prospects
    • South Cottonwood
    • Wild Basin -- main focus right now
    • Indian hills
    • Painted Woods
    • Red Bank
    • Montana
  • expanded top-tier with high intensity fracks in step-out areas
    • South Cottonwood now added to top-tier inventory
  • offset well results (3-month cum bbls of oil per 1,000 feet lateral)
    • South Cottonwood
      • pre-2016 wells: 2,122
      • offset 2016+ wells: 5,146 (up over 100%)
      • 2017+ Bakken average: 5,325
    • Painted Woods
      • pre-2016: 3.028
      • OAS recent tests: 6,111 (up over 100%)
      • 2017+ Bakken average: 5,325
    • Montana
      • pre-2016 wells: 2,361
      • offset 2016+ wells: 5,048 (up over 100%)
      • 2017+ Bakken average: 5,325
Peers:of 16 peers in the middle Bakken, OAS ranks #1 in Williston well productivity (raw data provided by outside source)
Midstream: in the Delaware, midstream development: Panther DevCo
Borrowing: no near-term maturities
  • S&P: BB-
  • Moody's: B3
Bakken midstream: OMP
  • Oasis' MLP
  • 2nd largest gas processor in the Williston Basin with the startup of Wild Basin Gas Plant II, December, 2018
Delaware Panther DevCo to OMP
  • Panther acreage: at the three-county area -- Loving, Winkler, Ward; just west of the Wink Oil Hub

Hess With Three New Permits -- June 17, 2019

DUCs: I'm sure this has been followed on twitter, like forever, but this is the first time I've seen it:

For me, getting DUC data means a whole lot more than weekly rig counts.

Of those 8,000 DUCs, only a thousand of them are in the Bakken. 

Back to the Bakken

Active rigs:

Active Rigs6262572878

Three new permits:
  • Operator: Hess
  • Fields: Tioga (Williams)
  • Comments: Hess with permits for a 3-well TI-Beauty Valley pad in section 14-158-95, Tioga oil field
Four permits renewed:
  • Whiting (3): three Schilke permits in Williams County
  • Resource Energy Can-Am: a Bervik permit in Divide County
Three producing wells (DUCs) reported as completed:
  • 35133, 1,748, Whiting, Dam State 41-16-4TFH, Epping, t5/19; cum --; runs south;
  • 35132, 1,573, Whiting, Dam State 41-16-3H, Epping, t6/19; cum --; runs south;
  • 35134, 1,798, Whiting, Dam State 44-9-6H, Epping, t5/19; cum --; runs north;
    • neighboring wells (all still off line; some off line longer than others):
      • 21041, 1,415, Whiting, 20711 State ... t12/11; cum 218K 9/18;
      • 21042, 1,204, Whiting, 20711 Mildred ... t12/11; cum 241K 9/18;
      • 28542, 2,041, Whiting, P Dam State .... t3/15; cum 272K 3/19;
      • 28541, 1,700, Whiting, P Dam State ... t2/15; cum 137K 3/19;
      • 28540, 2,614, Whiting, P Dam State ... t2/15; cum 162K 3/19;
      • 28539, 2,271, Whiting, P Dam State ... t2/15; cum 182K 3/19;

Wind Energy Initiative In Germany Collapses -- Wind Energy CEO -- June 17, 2019

Press release from "wind energy" advocacy site, May 10, 2019, builds on previous posts:
Screenshot headline / banner from the May 10, 2019, press release:

The story at the linked May, 2019, site:
The growth of onshore wind energy is collapsing in Germany, jeopardising both German and EU renewables targets. Germany installed just 134 MW of new onshore wind farms in the first quarter of 2019 – the country’s worst first quarter for onshore installations since 2000.

Germany is likely to install a total of just 1-2 GW of onshore wind this year. This is significantly down on the past five years when Germany installed an average of 4.3 GW per year. This is well below what Germany needs to meet its own 65% renewable electricity target by 2030 and to deliver its share of the EU’s 32% renewable energy target. Offshore wind will not fill the gap: Germany is due to build just 730 MW per year up to 2030.

This is in contrast with Spain, for example, which will build around 4 GW of new wind energy in 2019. Some of the slowdown in Germany is the result of failed auction systems in 2017, when a lot of community projects won without a permit. Many of these projects are still to be built due to more generous realisation timelines.

But permitting for new wind farms remains the underlying problem. The process used to take just 10 months but is now taking over two years. Public authorities are not applying deadlines and many wind farm projects are getting stuck in legal disputes. Plus there is a lack of staff to process the applications, especially at Bundesland level. Just 400 MW of new wind farm permits were awarded in Q1 2019, well below historical levels. All this has meant the last three onshore wind auction rounds were undersubscribed leading to rising prices.

WindEurope CEO Giles Dickson said: “Onshore wind energy in Germany is in deep trouble. The development of new wind farms has almost ground to a halt. The main problem is permitting – it’s got much slower, more complex and there aren’t enough civil servants to process the applications. It seriously undermines Germany’s ability to meet its 2030 renewables target and contribute to the EU target. And it’s affecting Germany’s wind turbine industrial base. Half of Europe’s 300,000 wind energy jobs are in Germany. But 10,000 have gone in Germany in the last five years. And this could get worse: there hasn’t been a single turbine order recorded in Germany in Q1 this year.
The reader who sent me the link, and who follows this a lot more closely than I do, suggests that the wind issue is much more serious in Germany that this article implies/suggests. That would make sense. The article is a press release from an advocacy, lobbying group. On the one hand, they want a bit of hyperbole to advocate their position, but if they tell us how bad it really is, they run the risk of getting even less support. 

We're starting to see the same thing in North Dakota. The ND PUC recently denied a permit for a wind farm in Burke County.

The Ridiculous Becomes The Ludicrous -- June 17, 2019

The raw data:
  • US oil and natural gas rigs drop by six, week-over-week.
Headline: Texas led all states in rig declines.

Texas produces oil and natural gas, but right now, in Texas, crude oil is the story. In fact, in the Permian and the Eagle Ford, operators probably wish that natural gas would just go away. Certainly in the Bakken operators would like to see 95% crude oil and 5% natural gas from their wells.

So, with that in mind, of the ... OMG ... decline of six rigs week-over-week how many of those rigs were in plays drilling for oil? Drum roll .... one rig.

The headline: Texas led all states in rig declines. So was Texas the only state to drop one oil rig, or did Texas drop only natural gas rigs? Either way, for Texas it's a non-story and actually for the rest of us, it's a non-story regardless.

The data is important, but it hardly deserves a stand-along tweet as well as a headline story. Making it part of a bigger report, like the weekly petroleum report or the weekly drilling report makes sense, but as a stand-alone story .... really?

One rig.

Just beating a dead horse.

But it provided a stand-alone post for the blog.

In Texas, Eight Ears For A Dollar

Sophia's favorite treat.

Fifty cents for four ears. I don't know how American farmers do it. 

On Friday, "they" had just dropped off two huge crates of corn at the Tom Thumb grocery store next to our apartment complex. I went to the store yesterday to get a couple of ears; completely sold out. 

Today, a smaller shipment and by tomorrow morning it, too, will be gone.

The CLR Colter Wells In Bear Creek

Disclaimer: these notes are to help me understand the Bakken. In a long note like this there will be typographical and factual errors. Much is left out. If this is important to you, go to the source.

Among many amazing details, note the drilling time when things go well -- vertical, three days; the curve, less than half a day; a long horizontal in three days. The operators in the Bakken are truly in their "manufacturing" stage. But with each well, they learn more about the geology. And the geology in the Bear Creek seems to have a different wrinkle -- and that might be an apt metaphor.

The wells:
  • 32897, 863, CLR, Colter 14-14H, 37 stages, 7.1 million lbs, Bear Creek, t3/19; cum 72K 4/19;
From the file report:
  • TD = 21,760 feet
  • spud date: February 13, 2018
  • TD date: February 25, 2018
  • hole sizes: 13.5 inches to 2,454 feet; 8.75 inches to 11,637 feet; and, 6" to 21,760 feet
  • within the Rocket prospect
  • KOP: 14 feet below the upper Bakken
  • vertical operations began February 12, 2018
  • curve began on February 15, 2018; curve completed in 9.6 hours
  • "Bakken shale collapse issues have been encountered in this region, and angles of intercept and shale exposure footage have become important data. CLR engineers have determined that entering the shales should be dont at angles no more than 65 - 68 degrees of inclination. On this well, the upper Bakken was intercepted at 67.74 degrees and exited at 76.96 degrees, with a total of 54' exposure. Fortunately, no shale collapse issues were experienced during drilling or the casing run."
  • the shoe was drilled out on February 17, 2018
  • sidetrack one was abandoned after striking the lower Bakken shale at 15,933 feet
  • discussion re: the strike
  • sidetrack 2 began at 13,690 feet
  • background gas as high as 1500 units but generally much lower
  • target was approx 13 feet thick, beginning 9 feet below the middle Bakken top, and extending to 22 feet below the same reference point
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

The next well:
  • 32894, 1,563, CLR, Colter 11-14H2, 37 stages, 7.1 million lbs, Bear Creek, t3/19; cum 78K 4/19; 
From the file report:
  • TD = 21,791 feet
  • spud date: January 25, 2018
  • TD date: March 14, 2018
  • drilling operations began January 25, 2018
  • vertical operations were completed on January 28, 2018
  • the curve was started/completed on January 29, 2018
  • drilling out of the shoe did not begin until March 11 
  • so, if I read this correct: drilling time
    vertical: 3 days
  • the curve: less than 1/2 day
  • horizontal: 3 days
  • trip gas in the horizontal hit 3,452 units
  • gas average: 1500 - 2000 units
  • target was 13.5 feet thick
  • the target top was 7.5 feet below the internal 1 shale base
  • the target extended to 21 feet below the same reference point
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

The third well:
  • 32892, n/d, CLR, Colter 9-14H, Bear Creek, t--; cum --;
From the file report:
  • frack data pending
  • TD = 21,800 feet
  • spud date: December 13, 2017
  • TD date: January 11, 2018
  • vertical drilling began December 13, 2017, and was completed on the evening of December 15 (less then three full days)
  • the curve took 11.25 hours
  • some casing challenges
  • drilled out of the shoe on December 21st; problems; the curve was re-built
  • upon re-entry, things went "wonderfully"
  • nice discussion of the curve build
  • target zone: 13 feet thick; 9 feet below the middle Bakken top, extending to 22 feet below the same reference point
  • discussion of major thickness differences in this area; increases risk of shale strikes
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

Another Fractionation Plant Being Considered Near Houston -- Keeping Texas Great -- June 17, 2019

Ohio-based MLPX is considering a half-billion dollar fractionation plant near Houston. Data points:
  • $460 million project
  • south of Houston
  • contingent upon tax incentives
  • school districts allowed to negotiate tax concessions
  • in this case, MPLX is asking Angleont ISD to tax the half-billion dollar project as if it were worth only $30 million for the first ten years
  • approval authority: the Texas Comptroller
  • construction: 500 workers during peak construction
  • 10 full-time jobs once complete;
  • full-time employees: at least $66K annually
Yes, it's a slow news day.

I was wondering when we would see this story -- it took less than a week for insurers to respond. From Bloomberg, oil tanker insurance premiums set to surge. 

Also from Bloomberg, President Trump is trying to make it more expensive for Gazprom to go ahead with that European Nord Streak pipeline link. Good, bad, or indifferent, past presidents have simply ignored these things.

Fifteen Wells Coming Off The Confidential List Today, Weekend -- June 17, 2019

SCOOP/STACK: from Reuters, an update -- data points --
  • SCOOP (South Central Oklahoma Oil Province)
  • STACK (Sooner Trend, Anadarko, Canadian and Kingfisher)
  • interest dims in Oklahoma shale as drilling results disappoint
  • the problem: the region's geology has proved more inconsistent than expected
  • also: more gas than initially expected
  • oil window across the play is limited
  • also the parent-child problem
    • poorer results form subsequent wells
    • perhaps more than any other US shale basin, the SCOOP/STACK has suffered from the "parent/chld" well problem, where secondary wells produce less oil than the original
  • the area has become a higher-cost US shale are for producers
  • this is probably the data point that led Reuters to the story in the first place:
    • Alta Mesa Resources Inc, which turned a $3.8 billion investment in the oilfield into under $30 million in just two years, last month said it may not be able to pay creditors. 
  • others also cutting CAPEX in Oklahoma
  • others narrowing development to best areas
    • CLR and MRO anchoring activity on two sub-areas
    • the STACK-Meramec
    • the SCOOP Woodford
  • breakeven since the start of 2018, per Rystad: around $54
  • higher than the Permian, Bakken, DJ, and much of the Eagle Ford
Back to the Bakken

Wells coming off confidential list over the weekend, today -- 
Monday June 17, 2019: 60 for the month; 249 for the quarter;
  • 34657, SI/NC, Petro-Hunt, USA 153-95-3B-10-3H, Charlson, no production data
Sunday, June 16, 2019: 59 for the month; 248 for the quarter;
  • 34867, SI/NC,  Hess, BB-Eide-151-95-3328H-13, Blue Buttes, no production data,
  • 34604, SI/NC, Slawson Wolverine Federal 10-31-30TF2H, Elm Tree, no production data, 
  • 34242, 969, Oasis, Nelson 5298 42--23 6B, Banks, t1/19; cum 86K 4/19;
  • 34241, 1,138, Oasis, Nelson 5298 42-23 6B, Banks, t1/19; cum 139K 4/19;
  • 34224, 492, Oasis, Nelson 5298 11-14 4T, Banks, t1/19; cum 90K 4/19;
  • 32897, 863, CLR, Colter 14-14H, Bear Creek, t3/19; cum 72K 4/19;
  • 32894, 1,563, CLR, Colter 11-14H2, Bear Creek, t3/19; cum 78K 4/19;
  • 32892, n/d, CLR, Colter 9-14H, Bear Creek, t--; cum --;
  • 27436, SI/NC, Petro-Hunt, State 154-94-31C-32-1HS, Charlson, no production data,
Saturday, June 15, 2019: 50 for the month; 239 for the quarter;
  • 34690, 1,058, CLR, Springfield 6-8H1, Brooklyn, t4/1; cum 15K after 18 days;
  • 34656, SI/NC, Petro-Hunt, USA 153-95-3B-10-3H, Charlson, no production data,
  • 35789, SI/NC, XTO, Bullberry Federal 24X-2DR, Lost Bridge, no production data, 
  • 34937, SI/NC, XTO, Darlean 41X-2G2, Alkali Creek, no production data,
  • 34866, SI/NC, Hess, BB-Eide-151-95-3328H-12, Blue Buttes, no production data,
Active rigs:

Active Rigs6162572878

Flashback: Director's Cut for June, 2016 -- (current data - April, 2019 -- here)
  • rig count: 27
  • crude oil production:
    • June, 2016: 1.03 million bbls
    • May, 2016: 1.05 million bbls
  •  natural gas production
    • June, 2016: 1.7 billion cfpd
  • ND sweet crude price: $33.74 / bbl
  • producing wells: 13,239 (all-time high at that time)
  • DUCs: 887
  • inactive well count: 1,486
RBN Energy: crude oil shippers start signing up for at least a few new pipes -- part 2. Archived.
A few months back, we discussed the quandary that crude oil shippers face when deciding whether to commit to proposed new pipeline capacity out of the Bakken and the Niobrara, and from the Cushing, OK, hub to the Gulf Coast.
The dilemma boils down to this: more capacity is needed, based on current constraints or projected growth (or both), but there’s some reluctance among shippers to make long-term commitments. Their worries are that production gains might slow and too much takeaway capacity might be built, resulting in bidding wars for barrels at the lease to fill shipper commitments. Well, in recent weeks there’s been a bit of a break in the project logjam; among other things, P66 and its partners have decided to proceed with the construction of both the Liberty Pipeline, from the Bakken and Niobrara to Cushing, and the Red Oak Pipeline, from Cushing to Houston and Corpus Christi via Wichita Falls, TX.
And that’s not all. Today, we provide an update on efforts to develop new pipeline capacity from North Dakota and the Rockies to Oklahoma and beyond.