A Random Update Of Permits In The Bakken So Far This Calendar Year -- October 8, 2019

2019 Permitting In North Dakota 

99% Bakken 

Projection: Based on the number of permits in each of the following months, the number in bold was the projected number of permits for calendar year 2019 had the rate for the entire year remained the same as that one month. For example, based on the number of permits issued in April, 2019, had that been the "rate" for the entire calendar year (2019), 1,582 permits would be issued for calendar year 2019.

• January, 2019: 1,495
• February, 2019: 1,434
• March, 2019: 1,578
• April, 2019: 1,582
• May, 2019: 1,660
• June, 2019:  1,557
• July, 2019: 1,671
• August, 2019: 1,495
• September, 2019: 1,107
• first 8 days of October, 2019: 1,688 

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Original Post

 
Disclaimer: I did this quickly. There will be factual / typographic errors. The numbers were counted quickly and may be "off" by two or three at the most, good enough for government work.

To date, for 2019, there have been 1,162 oil and gas permits which extrapolates to 1,509 for the year which is about average for a "good" year in the Bakken.

Of the 1,162 permits, this is how some of the numbers play out:

Company	As Of October 8, 2019
CLR	159
Hess	125
XTO	118
Whiting	82
BR	79
MRO	71
RimRock	65
Enerplus	57
WPX	52
Kraken	45
Slawson	44
Equinor	32
Bruin	29
EOG	14

CLR, not unexpectedly led at 159 permits. I was surprised to see Hess at #2 and pretty much in the same ballpark with 125 permits, and then even XTO. After that it drops off fairly quickly.

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More On Permitting

See this post.The update:

Projected Number of Permits for Calendar Year 2019

For the number of days in the calculations below, I'm using "number of days" through Sunday, July 14, 2019, this weekend.

It's possible I have made simple arithmetic errors.

The number of permits issued each month by the NDIC may differ from what I have in my database, but if so, it will be very, very close, and won't affect the overall results.

Based on the number of permits in each of the following months, the number in bold is the projected number of permits for calendar year 2019 had the rate for the entire year remained the same as that one month. For example, based on the number of permits issued in April, 2019, had that been the "rate" for the entire calendar year (2019), 1,578 permits would be issued for calendar year 2019.

• January, 2019: 1,495
• February, 2019: 1,434
• March, 2019: 1,578
• April, 2019: 1,582
• May, 2019: 1,660
• June, 2019:  1,557
• July, 2019: 1,671
• August, 2019: 1,495
• September, 2019: 1,107
• first 8 days of October, 2019: 1,688 
  

Based on the number of permits issued for the first calendar quarter of 2019, the number in bold is the projected number of permits that would have been issued for the entire calendar year had the rate been the same as that for the corresponding quarter. In other words, based on the number of permits issued in 1Q19, there would be 1,497 permits issued for the entire calendar year had that rate remained throughout the year.

• 1Q19: 1,497
• 2Q19: 1,071
• 3Q19: 1,428

I've checked this several times and I believe the numbers are accurate.

One can check the above projections with the actual number of permits issued in North Dakota over the past several years at this site:

• 2019 (estimate): 1,497
• 2018: 1,466
• 2017: 1,189
• 2016: 818 (price of oil tanked due to Saudi opening their spigots)
• 2015: 2,055
• 2014: 3,012
• 2013: 2,671
• 2012: 2,522
• 2011: 1,916

For newbies:

• North Dakota regulators generally approve permit applications in about 30 days
• permit applications should not be affected by the weather unless there is a lot of site visitation of which I am unaware, but certainly the 1,071 permits projected based on 2Q19 vs the 1,497 permits projected based on 1Q19 appears to validate that assumption; in ND, Jan-Feb-Mar are severe winter months; whereas Apr-May-Jun are much better weather months
• a permit is "good" for one year, but is easily renewed

My hunch:

• most operators determine CAPEX, number of rigs, permit applications, etc, six to twelve months prior to execution
• CAPEX is adjusted semi-annually when things are going well; quarterly when things seem a bit more bleak; and monthly, when things are going to hell in a handbasket
• the number of rigs and frack spreads correlate directly with CAPEX
• permit applications may or may not correlate with CAPEX; I don't know
• I would think operators would have a stack of permits in the hopper in draft status/nearly complete well in advance of submission; 
• it appears NDIC can issue as many as 20 or more permits in one day based on historical data; in other words, it's not the NDIC holding things back once operators decide to proceed (obviously the NDIC is not accomplishing the entire process in one day, but the point is that the number of permits issued in one day does not appear to be capped by the regulator)

Thesis:

• the weekly rig count, week-over-week, is meaningless in the Bakken
• the monthly rig count, month-over-month, may be slightly more meaningful than the weekly change
• the monthly permitting activity gives one a much better idea of future activity (and dare we say, production?) in the Bakken

If I could only choose one metric to follow the Bakken, it would be the rate of change (increase/decrease) in number of permits on a monthly basis. 

Having said that, even the number of permits issued each year is coming down, and production continues to rise.

A Look At 30 Horizontals In A Single Section In The Elm Tree Oil Field -- October 8, 2019

From today's daily activity report:

Eight new permits, #37053 - #37060, inclusive;

• Operator: CLR
• Fields: Elm Tree (McKenzie)
• Comments: 
• CLR has permits for an 8-well Angus Federal pad in SENW section 

Adding those eight locations to the previous activity, this is what the area now looks like:

In that immediate area, just looking at one section:

• five horizontals; producing wells, including the section line well (#33964)
• ten Simmental Federal / Charolais South Federal permits
• eight Angus federal permits
• seven wells on the confidential list
• total: 30 locations/wells

This is starting to become overwhelming. 

All Politics -- Nothing About The Bakken -- October 8, 2019

Death cross.

One can "argue" about the significance of 26.6 vs 26.4 but one needs to look at a whole lot more than those two numbers.

Link here. 

The game will be over before it even started:

• Biden:
• will put 720 million women back to work
• wants parents to put the phonograph records back on at night
• Ukraine
• Three strikes and he's out.

• Bernie:
• he was fading before the heart attack
• heart attack -- left field pop-up and he's out

• Buttigieg: on first

• Harris: on second

• Pocahontas: at bat

• Hillary: on deck
• knows Pocahontas will get a walk, get to first, advance all runners
• will come up to bat with bases loaded
• looking for a grandslam

Five DUCs Reported; CLR With Eight New Angus Federal Permits -- October 8, 2019

Active rigs:

$52.45	10/8/2019	10/08/2018	10/08/2017	10/08/2016	10/08/2015
Active Rigs	56	64	59	33	68

Eight new permits, #37053 - #37060, inclusive;

• Operator: CLR
• Fields: Elm Tree (McKenzie)
• Comments: 
• CLR has permits for an 8-well Angus Federal pad in SENW section 16-153-94, Elm Tree oil field
• see graphic at this post

Five producing wells (DUCs) reported as completed:

• 35129, 1,347, Whiting, Oppegaard 43-9H, Truax, t9/19; cum --;
• 35128, 1,748, Whiting, Oppegaard 43-9-2H, Truax, t9/19; cum --;
• 33703, 1,159, Whiting, Long 44-10H, Truax, t9/19; cum --;
• 33523, 2,095, Whiting, Long 44-10HU,Truax, t9/19; cum --;
• 34905, 2,323, Hess, SC-JCB-154-98-1720H-8,Truax, t9/19; cum --;

US Natural Gas Production -- The Shale Revolution -- A New USGS App -- October 8, 2019

Updates

Later, 9:34 p.m. CT: see comments. A reader mentioned that lifting costs in the desert were a whole lot less than those in the Bakken. This is as good a time as any to re-post "break-even" costs in the Bakken:

 
$8 / bbl in Mountrail County. $12 statewide.

Original Post

From a reader:

I didn't see much news on this, but the USGS has new a new application for US natural gas assessments.

The USGS shows a marginal increase in the Marcellus from 84 to 97 TCF.

In addition, there's an (initial?) assessment of the Utica at 117 TCF.

 This is showing the normal pattern of the USGS increases over time that we've seen in other plays (Bakken, Permian, etc.)

Also, while big, the USGS numbers are still quite lower than the Potential Gas Committee (PGC) estimates (which also tend to get bigger over time): http://potentialgas.org/press-release.

In round numbers, then, about 100 TCF for both the Marcellus and the Utica; the estimates will increase over time.

To put these numbers in perspective, see this post.

The "117 TCF" is well under what others have estimated:

• Utica, newly revised figures: 782 trillion cubic feet

From that linked source:

According to the new study’s estimates, the total Utica Shale play could hold technically recoverable volumes of 782 trillion cubic feet of natural gas and nearly 2 billion barrels of oil.

The estimates from a research partnership organized by West Virginia University represent the average of a wider range of possibly recoverable amounts of oil and gas in the Utica, which stretches beneath parts of Ohio, West Virginia, Pennsylvania and other states and includes neighboring oil- and gas-bearing geologic layers.

A 2012 U.S. Geological Survey assessment of the Utica Shale and underlying Point Pleasant formation pegged the technically recoverable undiscovered resources at 38 trillion cubic feet of gas, 940 million barrels of oil and 208 million barrels of natural gas liquids such as ethane, butane and propane.

 Regardless of the various estimates, the bottom line: the US remains "king of natural gas." From the USGS press release, September 11, 2019:

The Potential Gas Committee (PGC) today released the results of its latest biennial assessment of the nation’s natural gas resources, which indicates that the United States possesses a total mean technically recoverable resource base of 3,374 trillion cubic feet (Tcf) as of year-end 2018.

This is the highest resource evaluation in the Committee’s 54-year history, exceeding the previous high assessment (from year-end 2016) by 557 Tcf (increase of about 20%).

This is also the largest two-year increase in absolute resources between evaluations in the PGC history.

The increase resulted from reassessments of shale gas resources in the Atlantic and Mid-Continent areas and conventional and tight gas in the Mid-Continent and Rocky Mountain areas.

Only One Well Coming Off Confidential List Today -- October 8, 2019

Saudi Arabia: maybe things are not so back to normal?

Day rates: this was one of the top international energy stories last week. The first report was that tanker rates had gone to $10 million; then a second report, $12 million. Now, it is being reported that --

Occidental Petroleum has chartered the Very Large Crude Carrier Maran Andromeda to carry oil to South Korea for a record-setting price of $13.25 million, Reuters sources said on Monday.

Occidental is the largest Permian oil exporter from the US Gulf Coast, exporting a total 300,000b barrels per day, or 10% of all US crude oil exports. It has plans to double its crude exports next year (2020) although higher freight rates could dampen those prospects.

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Back to the Bakken

Plastics, North Dakota: continuing to be discussed; The Williston Herald.

Only one well coming off the confidential list today -- Tuesday, October 8, 2019: 25 for the month; 25 for the quarter:

• 30649, 2,108, CLR, Sorenson 4-16H1, Alkali Creek, this will be a very, very nice well, producing nearly 40,000 bbls in first full month of production; t5/19; cum 81K 8/19;

The CLR Sorenson wells are tracked here.

Active rigs:

$51.88	10/8/2019	10/08/2018	10/08/2017	10/08/2016	10/08/2015
Active Rigs	56	64	59	33	68

RBN Energy: AECO gas forwards mostly shaking off low Alberta storage.

With another month of anemic storage injections in September, Alberta natural gas storage levels remain on track to start the next heating season at a 13-year low. Still, while Alberta gas storage has been lagging well behind in terms of average injection rates and storage levels for many months now, forward winter contract prices for the Western Canadian gas price benchmark of AECO have budged only a little. There is potential for an improvement in storage injection rates during October after a recent regulatory approval affecting the Alberta gas pipeline system, but there is little time remaining in the current injection season to make much of a difference in inventory levels going into winter. Today, we conclude this two-part series with a look at why the AECO forward market remains largely unconcerned with low Alberta gas storage levels.