Director's Cut With October, 2015, Data Is Out -- December 9, 2015

Link here.

The Director's Cut is out, December 9, 2015, with October, 2015, data.

North Dakota oil production for the month of October actually increased by about 0.6%, almost a 7,000 bopd increase compared to the previous month, September, 2015. The EIA estimated the entire US crude oil production would decrease by about 45,000 bopd in October, compared to September. [Reminder: the EIA estimate is for October crude oil production; the Director's Cut released today is also October data.]

Because so much is carried forward from previous posts, there are likely to be errors in previous data; I would go to the source if this information is important to you.

Director's Cut

October, 2015, Data

October, 2015, data here.

I track the "cuts" here. 

Disclaimer: this update is always done in haste; typographical and factual errors are likely. This is for my use only. If this is important to you, you should go to the source. 

Note: facts and opinions are interspersed in the note below. Do not make any investment or financial decisions based on what is posted below; there will be factual and typographical errors. If this information is important to you, go to the source. 

The October data is posted at this link: https://www.dmr.nd.gov/oilgas/directorscut/directorscut-2015-12-09.pdf

Important data points:

• Today, pricing: $27.00
• Bakken price in November: $32.16
• Fracklog: 975 (105 less than at end of September, previous reporting period)
• Completions: 43 (123 in September, 2015) -- more wells going to SI/NC status
• Statewide flaring: 14% (big improvement from previous month, 20%) 

Delta, crude oil production: 

• 1,168,950 - 1,162,159 = 6,791
• 6,791 / 1,162,159 = 0.58% increase month-over-month

Oil:  

• October, 2015: 1,168,950 (preliminary)
• September, 2015:  1,162,159 (final, revised)
• August, 2015: 1,187,631 (final, revised)
• July, 2015: 1,206,996 (final, revised) 
• June, 2015: 1,211,328 (final)(second highest; highest was December, 2014)
• May, 2015: 1,202,615 (final)
• April, 2015: 1,169,045 (final)
• March, 2015: 1,190,502 (final); 1,190,582 bopd (preliminary)
• February, 2015: 1,178,082 bopd (revised, final); 1,177,094 (preliminary)
• January, 2015: 1,191,198 bopd (all time high was last month)
• December, 2014: revised, 1,227,483 bopd (all-time high)

Producing wells:

• October, 2015: 13,174 (preliminary, new all-time high if it holds)
• September, 2015: 13,036 (final revised -- new all-time high)
• August, 2015: 13,031 (final revised -- new all-time high)
• July, 2015: 12,965 (final revised -- new all-time high)
• June, 2015: 12,868 (final revised -- new all-time high)
• May, 2015: 12,679 (final revised -- new all-time high)
• April, 2015: 12,545 (final revised -- new all-time high)
• March, 2015: 12,443 (final revised -- new all-time high)
• February, 2015: 12,199 (final revised -- new all-time high)
• January, 2015: 12,181 (preliminary -- new all-time high)
• December, 2014: 12,134 (preliminary, new all-time high)
• November, 2014: 11,951 (revised); 11,942 (preliminary, new all-time high)
• October, 2014: 11,892; revised 11,942 (preliminary, new all-time high)

Permitting: 

• November, 2015: 154
• October, 2015: 152
• September, 2015: 154
• August, 2015: 153
• July, 2015: 233
• June, 2015: 192
• May, 2015: 150
• April, 2015: 168
• March, 2015: 190
• February, 2015: 197
• January, 2015: 246
• December, 2014: 251
• November, 2014: 235
• All-time high was 370 in 10/2012
  

Pricing: 

• Today, 2015: $27.00 (low-point since Bakken play began was $22.00 in December 2008)
• November, 2015: $32.16
• October, 2015: $34.37
• September, 2015: $31.17
• August, 2015: $29.52
• July, 2015: $39.41
• June, 2015: 47.73
• May, 2015: $44.70
• April, 2015: $38.33; $36.25 (lowest since February, 2009, and January, 2015) (all-time high was $136.29 7/3/2008)
• March, 2015: $31.47
• February, 2015: $34.11
• January, 2015: $31.41
• December, 2014: $40.74
• November, 2014: $60.61

Rig count:

• Today:  65 - lowest since November, 2009, when it was 63 (all time high was 218 on 5/29/2012)
• November: 64
• October: 68
• September: 71
• August: 74
• July: 73
• June: 78
• May: 83
• April: 91 (lowest since January 2010)
• March: 108
• February: 133
• January: 160
• December, 2014: 181
• November, 2014: 188

Director's comments:  [see source]

The number of well completions fell substantially from 123 (final) in September to 43 (preliminary) in October.

Drilling rig count: 

• rig count decreased 3 from September to October, decreased 1 from October to November, and increased 1 so far this month 
• dropped 5 from June to July
• dropped 5 from May to June
• dropped 8 from April to May
• dropped 17 from March to April 8
• dropped 25 February to March
• dropped 27 from January to February
• dropped 7 from November to December
• dropped 21 from December to January
• dropped 23 from January to date of previous month's Director's Cut

Well completions: 

• October 43 (preliminary)
• September 123 (final)
• August: 115 (final)
• July: 119 (final)
• June: 149 (final)
• May: 116 (final)
• April: 102 (final -- astounding drop)
• March: an astounding 194 (final)
• February: 42
• January: 63
• December: 173 (preliminary)
• November: 48

Weather: 

• no significant precipitation events
• 8 days with wind speeds in excess of 35 mph (too high for completion work)
• no days with temperatures below -10F

Wells waiting to be completed:  

• At the end of October, an estimated 975 wells waiting to be completed; 105 less than at the end of September (per NDIC) -- 1,091 - 975 = 116
• At the end of September, an estimated 1,091 wells were waiting to be completed; 98 more than the end of August (per NDIC)
• At end of August, an estimate 993 wells waiting to be completed; 79 more than end of July
• At end of July, an estimated 914 wells waiting to be completed, 70 more than at end of June
• At end of June, an estimated 844 wells waiting to be completed
• At end of May, an estimated 925 wells were waiting to be completed, no change
• At end of April, an estimated 925 wells were waiting to be completed, an increase of 45
• At end of March, an estimated 880 wells were waiting to be completed, a decrease of 20
• At end of February, an estimated 900 wells waiting to be completed, an increase of 75
• March, 2015, Director's Cut -- 825 wells -- an increase of 75-- January data
• Previous Director's Cut -- 750, a decrease of 25

Flaring: 

• capture target, current, January - December, 2015: 77% (had been 80%)
• capture target, April, 2016 - October, 2016: 80% (had been 90%)
• capture target, November, 2016 - October, 2018: 85%
• capture target, November, 2018 - October, 2020: 88%
• capture target, after October, 2020: 91%
• flaring capture percentage in October: 86%; percent flared 14%
• finally, the Tioga gas plant was down to 85% capacity (down slightly from previous month) capacity (92% last month; 90% prior; and, 93% previous to that)
• the Lake Sakakawea gas gathering expansion project was approved, but it was approved too late for the 2015 construction season, resulting in a one-year delay.

Gas capture statistics:  

• statewide: 86% (October 2014 target was 74%; CY 2015 capture target is 77%)
• FBIR Bakken: 86% (was 83% last month)

Fracking policies/regulations: (see source linked above; way too much to post)

Five (5) New Permits; New Operator In North Dakota -- December 9, 2015

Active rigs:

	12/9/2015	12/09/2014	12/09/2013	12/09/2012	12/09/2011
Active Rigs	65	190	193	181	200

Five (5) new permits --

• Operators: XTO (3), SM Energy, Prairie Hills
• Fields: Bear Creek, Smoky Butte, Grover (a Madison well)
• Comments: this is the first ND permit for Prairie Hills Oil & Gas (see below): #32377, Prairie Hills, McCarroll 1H, Grover oil field; Renville;

Wells coming off confidential list Thursday:

• 30981, SI/NC, EOG, Van Hook 75-1514H, Parshall, no production data,
• 31147, SI/NC, XTO, Ryan 14X-9F2, Siverston, no production data,

Hess renewed five permits, all BB-Federal A wells in section 5-151-95.

Producing wells completed:
28078, 849, Oasis, Helling Trust Federal 5494 42-22 9T,
29482, 3,371, Statoil, Sorenson 17-8 4H,

Prairie Hills Oil & Gas was first mentioned at the blog on October 6, 2105:

An operator I had not heard of before was noted in case #24528 of the October, 2015, NDIC hearing dockets:

• 24528, Prairie Hills Oil, Grover-Madison, amend, establish a 320-acre unit; a horizontal well, Renville County

Link here:
Prairie Hills LLC
200 East 1st St North # 210
Wichita, KS 67202
 
A privately held company in Wichita, KS.

Producing Wells Completed -- December 9, 2015

One of the more interesting data points for tracking the Bakken may be "producing wells completed." These are wells that had/have been drilled to total depth (including the horizontal segment) but for some reason were not completed at the time they reached total depth. Early in the boom, wells were not completed soon after reaching total depth mostly due to logistical reasons: a shortage of frack spreads or a shortage of sand, for example.

Then, during the peak of the boom, when there waere adequate resources, the fracklog began to grow because of operational reasons. Operators delay fracking on multi-well pads until all wells are drilled; in addition, operations on neighboring wells may affect fracking operations on another pad. There is a slowdown in fracking during the winter but that generally does not occur until January or February.

Starting in October, 2014, operators began drilling to depth but then shutting in the wells due to the low price of oil. In mid-2015, the NDIC gave the operators additional time to complete their wells, no longer holding them to the "one-year rule."

Sometime over the past year of tracking "producing wells completed," it started to become apparent that this might be a useful data point to track to better understand the Bakken.

Right now, I have just some very basic data, but there are some derivative data points yet to be tracked. For example, the wells that are being drilled now and not completed are in the very best spots in the Bakken. In addition, they are being drilled on existing pads and may positively impact production from existing wells.

Here are some basic data points from November, 2015:

• a total of 40 "producing wells were completed"
• the IPs were in line with historical IPs
• BR: 4
• CLR: 2
• Enduro: 1
• Hess: 4
• Newfield: 3
• Oasis: 3
• Petro-Hunt: 3
• QEP: 4
• SM Energy: 4
• Statoil: 4
• WPX: 2
• XTO: 6 

Under ideal circumstances, one can argue that a well will be producing oil in the state of North Dakota within six months of a permit being issued. In June, 2015, 193 permits had been issued. It looks like about 60% of wells are going to DUC status, or about 115 wells could have been drilled and placed on SI/NC status. Of those 193, forty were completed. Note: the "40" is an exact number based on daily activity reports. The number of permits issued is an exact number based on daily activity reports. However, the percent of wells placed on SI/NC (DUCs) is an estimate and may be off by a significant amount. But it gives me an idea of what operators are doing in the Bakken.

Permits issued in June, 2015, by operator:

• BR: 4
• CLR: 18
• Crescent Point: 11
• Denbury: 1
• Emerald Oil: 7
• EOG: 34
• Hess: 19
• HRC: 8
• MRO: 3
• Newfield: 2
• Oasis: 21
• Petro-Hunt: 8
• Samson Resources: 1
• Sinclair: 3
• Slawson: 16
• SM Energy: 7
• Statoil: 11
• Whiting: 10
• XTO: 7
• Zavanna: 2

North Dakota Production Increases Month-Over-Month -- December 9, 2015

Closing the poll on the sidebar at the right. North Dakota crude oil production increased month-over-month. The question was whether October production would be more/less than September production?

• more: 30%
• less: 68%
• no change: 2%

I was going to vote for "more" but I wouldn't have bet more than a cup of coffee. Perhaps, "too close to call" would have been better.

Regardless, at John Kemp, his tweet, North Dakota's oil production is holding up better than most forecasters predicted. North Dakota oil production up 5,000 bopd in October vs September, to 1.17 million bopd.

I haven't seen the figures yet, but I would bet a cup of coffee that Eagle Ford production decreased during the same period.

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Brent Vs WTI

Going forward, I think there is going to be more emphasis on "difference" between Brent vs WTI. I've talked about it before, though infrequently and briefly. But I think Brent vs WTI will become more relevant going forward. Here's one example, though the source has a "conflict of interest." is reporting:

The future supply security of Brent is at risk amid continuing cuts to the oil service capacity, according to analysts at Rystad Energy. While the global market is currently oversupplied with crude, Rystad Energy research shows that investment decisions for only 8 billion barrels were made in 2015, even though the oil industry needs to replace 34 billion barrels of crude every year. This amount is less than 25 percent of what the market requires long-term.

Rystad Energy numbers show that prior to the post OPEC meeting oil price decline, the number of jobs in the oil service industry was already cut by 16 percent for the top 50 oil service companies. These oil service companies had aggregated revenues of $300 billion and 950,000 employees in 2014. To date, 150,000 employees have been laid off from these 50 companies alone, and an estimated 250,000 oil service employees from the top 400 oil service companies have been fired globally.

Global exploration and production spending declined by 20 percent in 2015 and is expected to fall another 11 percent in 2016, marking the first consecutive annual decline since the mid-1980s.

Rystad Energy forecasts spending to reduce by a further 70 billion next year and has warned that additional spending cuts in 2016 could occur following the current post-OPEC meeting oil price slide. Jarand Rystad, managing partner at Rystad Energy, commented in a Rystad statement:

Oil prices continue to fall after OPEC failed to reach an agreement on output targets and decided to remove its obsolete output ceiling last week. This decision occurs at a time when oil companies are in the process of taking final decisions on spending programs for next year.

We see that for most new developments oil prices are below life cycle costs. As oil companies need to pay dividends and have incompressible taxes and royalties, the majority of upstream players are destroying value as we speak and do whatever they can to cut costs.

As a result, billions of barrels of crude are not being matured while global consumption growth is still very robust. Thus, a new shortage of crude is likely to come a few years down the road. When this happens, the oil service capacity will not be there to support the growth at the pace needed. There is then a risk that we will face a new era of steep cost inflation which again will drive up oil prices too much and negatively impact the global economy.

From wiki:

Brent Crude is a major trading classification of sweet light crude oil that serves as a major benchmark price for purchases of oil worldwide. This grade is described as light because of its relatively low density, and sweet because of its low sulfur content.

Brent Crude is extracted from the North Sea and comprises Brent Blend, Forties Blend, Oseberg and Ekofisk crudes (also known as the BFOE Quotation). The Brent Crude oil marker is also known as Brent Blend, London Brent and Brent petroleum.

The other well-known classifications (also called references or benchmarks) are the OPEC Reference Basket, Dubai Crude, Oman Crude, Urals oil and West Texas Intermediate (WTI).

Brent is the leading global price benchmark for Atlantic basin crude oils. It is used to price two thirds of the world's internationally traded crude oil supplies.

It looks like we have three demand regions:

• the US -- supplied by Bakken, Permian, Eagle Ford, western Canada, Mexico, Venezuela
• Europe -- supplied by Brent, Mideast
• China -- supplied by Mideast, Russia

Timing will be very interesting. The buzz in Washington is that Congress will eventually allow US exports of oil but in exchange for huge demands made by politicians. It will take awhile for the ban on US oil exports to become law -- if the timing is right, it could happen just about the time we see huge Brent supply issues as predicted by Saudi Arabia.

This is where I stand:

• $30 - $40: trading range for WTI through May, 2016
• $45 - $55: trading range during driving season, from May on, 2016
• $60 - $65: trading range after 2016 and lasting for quite some time (measured in years)

SPR, Commercial Crude Oil Stock WIth More Than A Year's Worth Of Import Protection -- EIA -- December 9, 2015

From the EIA today:

As a member of the International Energy Agency (IEA), the United States is obligated to maintain stocks of crude oil and petroleum products, both public and private, to provide at least 90 days of import protection and to collectively participate in the release or sale of oil supplies to help balance a shortage among IEA members in the event of a severe energy supply disruption. Based on September levels of net crude oil and petroleum product imports, the SPR alone holds crude oil stocks equivalent to 156 days of import protection.

Including average levels of commercial stocks over the past 5 years, total days of import coverage provided by strategic and commercial stocks is currently 450 days.

I believe the US SPR holds about 700 million bbls of crude oil. 700 / 156 = 4.5 million bopd for import protection. 450 x 4.5 = 2,000 million bbls of crude oil in commercial + SPR storage. So I guess that means there's about 1,300 million bbls of crude oil in commercial (non-government) storage. I don't know. RBN Energy would know.

Of course this does not include additional storage currently being built throughout the US, or the amount of oil sitting in DUCs that could come available in less than a month.

1,000 DUCs x 20,000 bbls / month (the first full month) = 20 million bbls in North Dakota alone. But that is interesting. 1,000 DUCs sounds like a lot, but 20 million bbls, at a million bopd, amounts to just 20 days of current production. Disclaimer: I often make simple arithmetic errors.

Well, look at that. My "2,000 million bbls of crude oil in commercial + SPR storage" is a bull's eye. Wow. See this link, a dynamic link. That's pretty incredible that the numbers work that well. I'm going to get myself another cup of coffee.

Milestones:

• prior to 1975: commercial storage, only
• 1975: SPR begun by US government
• 1985 - 2004: steady stay; flat, background variability, 1,600 million bbls
• 2000: Bakken mini-boom begins in Montana
• 2007: Bakken boom begins in North Dakota
• 2009 - 2014: new floor established, around 1,750 million bbls
• 2015: step up to 2,000 million bbls

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The Fat Python

We don't need more oil production, we need more processing facilities, and we need more demand.

From Platts, previously posted.

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Global Crude Oil Growth: 2014 - 2016 (Inclusive)

The growth in global production in 2014 was about 2.55 million bopd. In 2015, growth will be about the same (2.5 million bopd) though the market share will be significantly different. In 2016, growth at 150,000 bopd will be "flat."

My thoughts:

• 2014: about 1 million bopd oversupplied (globally)
• 2015: the chart is an estimate, but the year is almost over, so it’s probably pretty accurate; about 2 million bopd oversupplied is what we are being told, and that’s about what the growth rate was, 2.55 million bopd in growth
• 2016: the growth is a net 150,000 bopd which suggests supply/demand more in balance, but for the entire year of 2014 there was probably an excess of 1 million bopd produced, and in 2015, an excess of 2 million bopd produced. That excess is sitting in government strategic reserves around the world, in commercial storage around the world, and there is no doubt, a lot unaccounted for. 

Since the US cannot export oil, it is very likely that US production would have fallen in 2015 regardless of what OPEC did. Producing at maximum rates, OPEC growth was about 1 million bopd. It seems to me that OPEC's current problems are totally self-inflicted. Had OPEC simply agreed to cut production by a paltry one million bopd, prices would have stayed historically high. By not cutting back on production, OPEC is giving their oil away at $40/bbl.

Look at the negative growth in the North Sea, especially in 2016. Combining such a huge negative growth with depressed prices suggest that England and Norway may feel the brunt of the slump.

Update On TransCanada's Upland Pipeline And ETP's Dakota Access Pipeline Projects Staging Areas West Of Williston -- December 9, 2015

Last week this was posted:

Consider that since 1980, the world has produced just under 900 billion barrels of oil -- and its proved reserves actually went up by just over 1 trillion barrels in that time.  

Let's parse that last sentence. Since 1980 -- 35 years -- the world has produced less than 900 billion barrels of oil. During that time global reserves actually went up by 1 trillion bbls.

Does anyone remember the estimated crude oil reserves in the Bakken alone? Five hundred (500) billion bbls. A lot of companies are going to go bankrupt or otherwise disappear but the Bakken oil is not going to go anywhere, and operators are not going to forget how to frack. And with less than 60 active rigs and 1,000 wells drilled to depth but not completed, and production still at one million bopd, it's not difficult to see that if push comes to shove, North Dakota can easily get to two million bopd.  

That puts the following story into perspective. The Dickinson Press is reporting that pipeline companies continue to "lay big bets on a big oil future in the Bakken."

In the 1804 Industrial Park west of Williston, TransCanada bought a 30-acre parcel to stage material and pipe for its Upland Pipeline project, and Energy Transfer Partner bought a 50-acre parcel to stage material and pipe for its Dakota Access pipeline.

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A Note to the Granddaughters

The other day I mentioned how seriously Texans take their sports. Yesterday evening our oldest granddaughter participated in another cross-country meet. In her "heat," there must have been somewhere between 100 and 200 girls. It looked like there were about five schools competing. Overall, she took 19th in her heat, and appeared to have taken 2nd place in her school. In the immediate Grapevine area, it appears the girls' team from Colleyville that is the team to beat. It appeared that the entire Colleyville girls' team led the entire heat across the finish line.

Wednesday, December 9, 2015

Active rigs:

	12/9/2015	12/09/2014	12/09/2013	12/09/2012	12/09/2011
Active Rigs	65	190	193	181	200

RBN Energy: running on empty -- Permian Basin refinery and crude gathering system expansions.

Refiners operating in the Permian Basin enjoyed healthy margins over the past four years as takeaway pipeline congestion discounted the price of local crude compared to market centers at Cushing, OK or the Gulf Coast. Although that trend reversed for a few months this summer when a shortage of crude at Midland caused prices to spike higher, the market is once again favoring local purchasers. As a result, refiners have invested in infrastructure to increase deliveries of local crude to their refineries as well as leveraging their gathering pipelines to double as takeaway routes for producers shipping outside the basin.  Today we continue our review of Permian infrastructure build out.

In Episode 1 we summarized the changing balance over the past year between Permian crude production and pipeline takeaway capacity out of the region. With new pipelines coming online since the end of last year to Houston (the 300 Mb/d Plains All American/Magellan Midstream Partners BridgeTex pipeline) Corpus Christi (the 250 Mb/d Plains Cactus pipeline) and Nederland (the 200 Mb/d Sunoco Logistics Permian Express II pipeline) takeaway capacity out of the basin is looking overbuilt – especially considering the new 540 Mb/d Enterprise Products Partners Midland to Sealy pipeline expected online in mid-2017. 

Meantime production overall in the Permian is slowing down although it looks to be still increasing slightly. Yet Permian wells remain among the most productive in U.S. shale plays and drilling continues in the sweet spot areas of the play – the Midland and Delaware basins. Consequently there is considerable pipeline infrastructure being built out to connect new production to the big takeaway pipeline hubs in the Permian.

In Episode 1 and Episode 2 we updated progress on Permian gathering projects first detailed last summer in our “Come Gather ‘Round Pipelines” series. Most of these projects are still on schedule although the focus and scope of some has changed. This time we look first at progress on projects by two Permian refiners to increase crude supply options and then at more recently announced infrastructure projects operated by Energy Transfer Equity subsidiary companies.