Saturday, March 31, 2018

Random Look At Production Jump In QEP Wells As Part Of The Company's Re-Frack Program -- March 31, 2018

I went through QEP's "oldest" 193 permits/file reports to see if I could get some insight into their re-frack program.

The 193 permits started with #16652, and ended with #25860.
  • the oldest permit: #16652, drilled back in 2007; jump in production in 2016, but likely not due to re-frack
  • the most recent permit: #25860; has not been re-fracked
A quick look, based on production profile, suggested these wells, of the 193 wells I looked at, 12 might have been re-fracked based on jumps in production:
  • Heart Butte, #24207, #24209
  • Heart Butte, #23097
  • Heart Butte, #23093
  • Blue Buttes, #21564
  • Heart Butte, #20964,
  • Grail, #20780
  • Blue Buttes, #20591
  • Deep Water Creek, #20271 
  • Deep Water Creek, #19683
  • Deep Water Creek, #18991
  • Deep Water Creek, #17940
I may have missed some and it's possible some of these were not re-fracked (but if not, hard to explain huge jump in production)

[An aside" I thought these wells were re-fracked but it turns out that despite how "old" these permits were, these wells were fracked for the first time in early 2017: Heart Butte, #25407 - #25412.]

Wells With Huge Jump In Production

24207 (FracFocus: re-fracked):
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

24209 (FracFocus: re-fracked):
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

23097 (FracFocus: re-fracked):
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

23093 (FracFocus: fracked):
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

21564 (FracFocus: no data that this well was re-fracked):

20964 (FracFocus: re-fracked):

20780 (FracFocus with no data that this well was re-fracked):

20591 (FracFocus with no data that this well was re-fracked):

Anyway, you get the idea.

Breakeven Prices By Basin -- Great Survey: Sent By A Reader -- March 31, 2018

From a reader who sent it in as a comment to an earlier post:
The Dallas Fed was out with a survey of executives from 140 oil companies this week, and one of the questions they asked was "What WTI oil price does your firm need to profitably drill a new well?"
Answers from the various Permian plays averaged lower than elsewhere, but not by's the page with the results from the 1st quarter's special questions: link here (
A lot of these links break over-time. This survey is a keeper; one may want to archive it.  It's a great site: it is very interactive with downloadable charts and data.

The first graphic:

More at the linked article.

One comment: I'm amazed at the range with regard to answers to both questions, but particularly the range at which companies can be profitable -- as low as $20 in the Permian (Midland) where the low is $40 in the Bakken.

Is QEP Ready To Exit The Bakken? Focus On The Permian? QEP With Successful Re-Frack Program In The Bakken -- March 31, 2018

Disclaimer: this is not an investment site. Do not make any investment, financial, job, travel, or relationship decisions based on anything you read here or think you may have read here. If this is important to you, go to the source.

Note: in a long note like this, there will be factual and typographical errors. Comments and opinions may be interspersed with factual notes. 

Earnings Call: QEP

From the earnings call, 4Q17, QEP, over at SeekingAlpha:
  • earnings:
    • 4Q17: $195 million
    • 3Q17: $193 million
    • 4Q16: $175 million
  • production:
    • 4Q17: 12 million boe (decrease primarily due to the Pinedale divestiture in 3Q17
    • 3Q17: 14 million boe (Pinedale: contributed 3 million boe)
Excerpts and data points from the earnings call follow.

  • Williston oil volumes were up about 334,000 barrels due to our refrac program
  • in the Williston Basin, we began our refrack program using a design which was closely patterned after the successful methodology that we are utilizing in our Haynesville wells. As a reminder, because of well spacing in the Williston, we have to shut in offset wells during these refracs and also obviously during new well completions, which has a negative impact on production volumes. While we're still fine-tuning our re-frack design, we're very encouraged by the early results, and we look forward to continuing the program in 2018. 
  • see this post for random look at jump in production suggesting re-frack
  • On a per unit basis, lease operating expenses were $6.58 per boe, which is up $1.19 per boe from the third quarter due to higher workover and repair expenses, primarily in the Williston Basin
  • capital expenditures on an accrual basis for E&P activities in the fourth quarter were $372 million, an increase of about $45 million from third quarter
  • CapEx in the Permian Basin was $215 million which included $18.9 million from midstream infrastructure
  • CapEx in the Williston Basin was about $88 million
  • CapEx in Haynesville was about $58 million.
Conversion from natural gas to liquids:
Through a series of acquisitions and two world-class oil provinces, first, in the Williston Basin, and then in the Permian, and through divesture of non-core gas-weighted assets in the Midcontinent and the Rockies, we successfully increased liquids from less than 15% of total production in 2011 to almost 50% last year.
Comment: this has been quite a ride watching this company. I remember when it entered the Bakken -- acquiring the "holy Grail/Helis Grail" and wondering how a "natural gas company" would do in an oily play. To say the least: I am more than impressed.
If there was one disappointment for the company: the failure to unitize the Grail oil field. I think royalty owners did themselves and QEP a "disservice" (if that's the best word) when they voted against unitization.
Exiting the Bakken:
  • we plan to return cash to shareholders through a significant share repurchase program
So, how are we doing it? We outlined a couple of strategic initiatives. First, we've engaged financial advisors to assist us in the divesture of our Williston and Uinta Basin assets.
And when I say Williston assets, obviously there's two assets: there's a South Antelope asset and the Fort Berthold asset. We'll present those as two separate packages, but obviously, we'll allow bidders to make offers on the one or both of those assets. And we also will have an advisor engaged to divest at our Uinta Basin assets. 
Focus on the Permian:
We also announced a number of financial initiatives. First, we plan to use the proceeds from asset sales to fund development of our Permian properties until the program reaches operating cash flow neutrality, which we expect to occur in 2019. 
Frack spreads:
  • on the 95 Permian completions in 2018, how many frac crews do you need to operate that plan?
  • We'll average two. We may pick up an occasional third crew, but our frack efficiency is quite good.
Tank-style development of the Permian
  • look at the slides below and read the conference call notes describing these slides
  • go to the QEP website
  • go to "slides" (I assume this presentation will disappear over time)
  • slides 11 - 13 are the core of the "tank-style" development discussion

Week 13: March 25, 2018 -- March 31, 2018

WTI closes the week right about at $65. A pretty good week for WTI and Mike Filloon predicts WTI could hit $70 by June, 2018 -- he feels $75 is a 'bridge too far." The US economy is surging though one might not be able to see it in the headlines; US first time unemployment claims at 45-year low; final GDP reading for 4Q17: 2.9%, much better than the prior reading of 2.5%.

Concho is now the biggest operator in the Permian.

The top story of the week, although it's been reported off and on for the past few months: CLR reports that Bakken EURs have increased form 430 mboe in 2011 to 1,100 mboi in 2018

MRO reports an incredible pad in Antelope oil field
Whiting brings Peery State (#16463) back to life
Slawson's Matilda Bay (#27635) is showing some life
CLR's Syracuse and Chicago wells should soon be coming off confidential play
MRO re-accomplishing a failed frack 
Filloon does not see evidence of shale operators running out of drilling locations
Active rigs jump to 62, recent high, in the Bakken

CLR EUR type curves up to 1.1 million bbls
CLR's Bud wells in Crazy Man Creek show nice jump in production
Early production numbers for Oasis Patsy wells are incredible
SHD's "Golden" well has been added to the list of "monster wells"
CLR's Quale production jumps

How the DAPL impacts Guernsey

Bakken 101
Production per rig, the Bakken beats all other plays

Bakken Economy
2017 taxable sales and purchases: up 24% in the Bakken; -3% for most of the rest of the state
ND prepares for infrastructure build-out; thousands of job openings hamper ND's growth

Other formations
A Madison well has a jump in production; month-over-month, production jumped 20x; Madison well fracked; 

FWIW: Filloon On The Eagle Ford -- March 31, 2018

Link here over at SeekingAlpha:
  • Eagle Ford production per location improved 20% yoy from 2016 compared to Midland's 32.5% and the Delaware's 18%
  • we expect more locations in DeWitt County as it continues to outperform on an oil production basis
  • although non-core areas are not nearly as prolific, there is a rather wide area that can be developed with very good payback times
  • a number of huge Eagle Ford locations have been completed recently, and although many have targeted the Austin Chalk it benefits the play
Our recent articles on the Permian's well design driven oil production improvements is also seen in other US plays. The evolution of design has been occurring over years. It is in Texas, Oklahoma, North Dakota, Colorado, Ohio and Pennsylvania. Each play will react differently to those changes.
We have seen a number of huge wells from several operators in the Eagle Ford. The Permian focus has drowned out talk of Gonzales and Karnes counties.
We think the Eagle Ford has been overlooked, but recent monster wells in the core could become more often than not. Better economics should push operators to increase production in the coming months as oil prices trade higher. We think WTI will increase to $70/bbl or $75/bbl this driving season.
These are the wells (indicated by the arrows) that interest me:


Friday, March 30, 2018

Hands Down, The Bakken Beats All Other Oily Plays -- Production / Rig -- But On BOE/Rig? The Eagle Ford


April 3, 2018: see this post for an update on this subject.  

Original Post 

From a May 17, 2014, post, production per rig:
It's been a long time since I've looked at this metric.

A huge thanks to a reader for a note that made me think of doing this.

So, in January, 2014, productivity per rig, based on the chart above:
  • the Bakken: around 500 bbls/rig
  • the Eagle Ford: about 475 bbls/rig
  • the Niobrara: about 350 bbls/rig
  • the Permian: not even 150 bbls/rig
So, how have things changed in four year? From the EIA (a dynamic link), the Bakken still leads all four major oily plays:
  • the Bakken: around 1,450 bbls/rig -- almost 3x greater than 4 years ago
  • the Eagle Ford: about 1,400 bbls/rig -- ditto, and very close to the Bakken (on a "boe" basis, the Eagle Ford would probably beat the Bakken -- but it would be close and might vary month-to-month)
  • the Niobrara: about 1,200 bbls/rig -- about 3.5x better than 4 years ago
  • the Permian: about 600 bbls/rig -- 4x better than 4 years ago -- but the Bakken is about 2.5x better than the Permian

Tesla Watch -- March 30, 2018 -- When It Rains, It Pours


March 31, 2018:

Later, 9:15 p.m. Central Time:

Later, 8:54 p.m. Central Time: it's being reported Friday night, just before a 3-day holiday weekend that:
Later, 8:27 p.m. Central Time: from ZeroHedge --

Original Post

Based on open sources from across the net, but mostly from "@TeslaCharts" over at twitter, this is my 30-second, elevator speech on Tesla's first quarter, 2018:
The "final" numbers are in because it's Easter Friday and no more deliveries for the month (March) will be made by Tesla.

Based on VIN registration numbers, Bloomberg and "Tesla Charts" (twitter) has the estimates for 1Q18.

It appears that Tesla "smashed" records for delivery in the last two weeks of the quarter, which will result in total numbers for first quarter 2018 being "respectable."  Those who love Tesla will say this proves Tesla is doing very, very well; those who hate Tesla will have the numbers to prove their point. The SEC filing only said they would "reach" 2,500/week by the end of the quarter, not "sustain 2,500" week after week after week. So, technically, it's possible Tesla will have reached 2,500/week by the end of the quarter because of the last two weeks of delivery but averaging over the entire 12 weeks, it will be far less.

This explains (at least for me) why Musk waited to announce a capital raise. If the numbers are as good as the estimates suggest, he will have more fire power going to the banks and the venture capitalists to get more cash or a better deal.

All eyes will be on deliveries to Norway.
From "@TeslaCharts," this chart is going to blow away Tesla bulls (and the rest of us). Nissan Leaf is clearly the global winner:
But there's an even bigger story here, actually two bigger stories here:
  • Tesla does not have a moat when it comes to EVs; lots and lots of competition
  • Nissan Leaf might not be seen as a Tesla competitor, but certainly VW and BMW are 
And see below, BMW has no plans to even ramp up until 2020 -- and they are still out-selling Tesla in Norway.  

BMW will not mass produce electric cars until 2020 because its current technology is not profitable enough to scale up for volume production, the chief executive said on Thursday.  
It's hard for me to believe that a car company like BMW feels their EVs won't be profitable until 2020 and the impression I get from Elon Musk is that he feels his cars already are profitable (I'm probably wrong on that).
With regard to Model 3, from twitter:
Wasn't Model 3 the Tesla for the rest of us?

US Crude Oil Production -- Hubbert Peak Oil Theory Revisited -- March 30, 2018

US crude oil production. 

Link here.

I find it incredible such "authoritative" sources as Wikipedia have not updated their "Hubbert Peak Theory" post. Hubbert Peak Theory describes a bell-shaped curve, not "twin peaks."

US Saudi Crude Oil Imports Hit 32-Year Low For Month Of January -- Have To Go All The Way Back To 1986 -- March 30, 2018

Link here. And the difference between January, 2017, and January, 2018, is not subtle. Ouch.

Meanwhile, US crude oil exports hit an all-time high for the month of January, going back to when records were first kept. Link here.

"Drill, baby, drill." Making American great again.

Spot price of WTI (at Cushing), rounded, link here:
  • end of March, 2018: a "solid" $65
  • end of March, 2017 (one year ago): a "less than solid" $50; closer to $47 - $49 
That's really quite remarkable. 15/50 = a 30% jump. And many operators have been able to cut costs over the past year. If oil companies were "evaluated" like analysts "evaluate" Tesla, we would all be gazillionaires.

Random Update Of An Old EOG Short Lateral In Parshall Oil Field -- March 30, 2018

For newbies: Some folks keep talking about newer wells in the Bakken affecting older wells in a negative manner. That's possible. I don't know. I just see a lot of these examples, where there is a jump in production in an older well when neighboring wells are fracked.

In the production profile below, between early 2015 and early 2013, just two years:
  • a jump in production from 2,000 bbls/month to 7,000 bbls/month, November, 2013
  • a jump in production from 5,000 bbls/month to 8,000 bbls/month in October, 2014
Not only is there a jump in production for a month or two, but the affect lasts several months, extending the period in which there is higher production, affecting a) the decline rate; and, b) the EUR.

Note: prior to neighboring wells being fracked, this well (#16543) was down to 2,000 bbls/month, arguably a very mediocre well. That was back in March, 2013. After neighboring wells were completed, not only was there a significant jump in production on two occasions, but the baseline production was up to 4,000 bbls/month.

A Bakken trope/meme (I don't know if it's a myth): new wells will result in less production from older wells. Example after example proves this is not the case.

The well, a single section EOG well in Parshall oil field:
  • 16543, 1,015, EOG, Florence 1-04H, Parshall, t7/07; cum 511K 1/18;
Earlier production:

The neighboring wells and the test dates of those wells:
  • 25254, EOG, t11/13;
  • 27042, EOG, t8/14
Remember, the index well is a short lateral. Had this been a long lateral, one can argue that total production would have been double what we see here.