March 3, 2021: the Texas Freeze.
September 1, 2020: no way, Jose. Yes, way. Way overpaid.
August 17, 2020: the August, 2020, dashboards; the Bakken beats the other two;
August 10, 2020: Permian oil shut-ins end at $40/bbl but a production decline looms. RBN Energy.
July 26, 2020: huge rebound for the Bakken; set all-time record for rig efficiency;
June 26, 2020: the big loser -- New Mexico.
June 15, 2020: Argus Media calls it -- the Permian wins.
June 12, 2020: Bakken vs Saudi Arabia? XOM's decision.
May 17, 2020: oilprice.com -- which state is hit hardest?
May 1, 2020: February, 2020, data -- EIA.
April 13, 2020: the Bakken still has bragging rights.
April 3, 2020: ProPetro launches mass layoff in Midland. Link to Rigzone here.
March 17, 2020: Apache, EOG. The former suspends all drilling (a Permian operator); the latter remains focused on the Delaware.
March 15, 2020: flaring triples in two years in the Permian.
March 15, 2020: Oasis corporation presentation, February, 2020.
March 15, 2020: Oasis has had their play in the Permian for two full years. They have two rigs in each play. In the Bakken: 80,000 boepd. In the Permian, 8,000 boepd. And per their February presentation, Oasis has some of the best locations in the Permian.
March 10, 2020, OXY: cuts dividend from 79 cents to 11 cents. Major CAPEX cut. OXY left the Bakken years ago; if a pure Permian play (from my point of view). From Street Insider:
Occidental Petroleum Corporation announced today that its Board of Directors approved a reduction in the company’s quarterly dividend to $0.11 per share from $0.79 per share, effective July 2020.
The company also announced it will reduce 2020 capital spending to between $3.5 billion and $3.7 billion from $5.2 billion to $5.4 billion and will implement additional operating and corporate cost reductions. [A 30% cut in CAPEX.]March 10, 2020, MRO: well, that certainly did not take long. The original post was posted yesterday. Today this:
- Marathon Oil pre-market after announcing an immediate capital spending reduction of at least $500M from its previously planned 2020 capital spending budget of $2.4B.
- The revised capex of $1.9B or less represents a ~30% reduction from 2019 levels.
- Marathon says it will suspend further resource play exploration drilling and leasing activity, suspend all operated drilling and completion activity in Oklahoma, and "meaningfully reduce" operated drilling and completion activity in the Northern Delaware.
- The company says it maintains a strong financial foundation, ending 2019 with ~$3.9B of liquidity and no near-term debt maturities.
This is really going to be interesting. [You are going to see that sentence/phrase/word many, many times over the next few weeks.]
This all began with a note from a reader when he/she sent me this Zero Hedge link.
So, everyone agrees: the price of WTI is going to drop significantly. Now what?
Disclaimer: I am really, really biased, and really inappropriately exuberant about the Bakken. Not from the investment angle, but from most non-investment angles. We've discussed this often on the blog. See welcome/disclaimer.
Disclaimer: this is not an investment site. Do not make any investment, financial, job, career, travel, or relationship decisions based on what you read here or think you may have read here.
Disclaimer: I do not follow the Permian, except peripherally. I do not "know" the Permian; I do not understand the Permian; I have my own worldview (myth) about the Permian.
I replied to the reader who sent me that Zero Hedge link above with this "not-ready-for-prime-time" reply which I will now post and open to discussion:
By the way, this will give us a chance to see which is more resilient? The Bakken or the Permian?
I wonder if the break-even price for about half of the Bakken production is $20/bbl or less. In other words, if operators were to stop all drilling except in a few areas; complete the backlog of DUCs, re-frack older wells in Tier 1 locations, drop the number of active rigs in half (or maybe to a quarter) -- production might drop to half current production but break-even might be $20 or less.We're talking survival here, weathering the storm for six months.
So, take that "not-ready-for-prime-time" reply and look at this morning's Bakken report.
- the number of active rigs is as high as ever, trending up over the past few days, and now at 55
- comment: the "current" rig count has nothing do with "current" events
- operators have a 10-year strategy; a 5-year plan; a one-year look-ahead CAPEX; a semi-annual re-set (usually tied closely to feedback from their lending institutions every six months);
- during a crisis, the semi-annual re-sets contract to quarterly meetings,
- if things are really, really bad for any specific operator, those re-set meetings are held monthly
Two months ago, the rig count in North Dakota was set for June, 2020: rigs were moving; contracts were signed; roughnecks were checking their Google maps.
Today, those directors and their lenders are in panic mode. "Panic" may be too strong a word: perhaps "concern" is a more politically correct term.
My hunch is that the semi-annual re-set will occur earlier than usual. If there is a change in the number of active rigs based on current events we won't see that at least for another month.
Break, break. Or will we? This is very, very interesting. [There's that word again.] What is the cost of dropping rigs sooner than planned? The cost of getting out of the contract.
In off-shore drilling and in conventional drilling, the drilling time was significant. Once in place and drilling, the operator would complete the well. A snapshot would reflect that in the number of rigs operating at any given time.
Drilling in the Bakken? And I assume this is true throughout the shale plays -- they can drill to depth in six days. The average, I suppose, is closer to ten days. The outliers might move the median and the mean to the right (more days). So, all those 55 rigs that are active today -- two weeks from now every well that is being drilled by those 55 rigs will now be drilled to depth.
If the situation is not improving, or getting worse, heaven forbid. operators can start dropping rigs en masse over the next two weeks incurring only the cost of the contracts, write-offs, etc. It will be a financial decision (well, duh). By the way, another digression. Remember: operators contract with a refiner to provide a certain amount of oil on a given date. It is cheaper to buy oil on the open market for $25/bbl or drill that next Bakken well costing $65/bbl? This is not rocket science. Operators with $55-hedges/collars/whatever they're called for FY2020, could be looking pretty good. I don't know. Another digression.
Bottom line for newbies: shale operators can turn on a dime compared to those working off shore. The number of active rigs today reflects 10-year-strategies, 5-year plans, one-year budgets; and semi-annual re-sets but in a crisis, shale operators can drop rigs in two weeks.
Wow, that was a digression.
This is what I really wanted to talk about: this morning's Bakken report (which included the active rig count). Look at two things.
First, DUCs. What do you see? Since Thursday last, eleven wells have been released from confidential status. Of those eleven permits, only one was a DUC. Most of these wells were completed some months ago and are now reporting. Experts suggest that if we get into crisis mode, we will see more DUCs. We've talked about that before. Won't re-hash, except to say the experts were talking about the Permian, ignoring what was happening in the Bakken. I track Bakken DUCs here. In the big scheme of things, unlike what the experts were saying about shale, there has not been any real change in the number of DUCs in the Bakken.
What would the break-even be for Bakken oil if all drilling stopped immediately and operators used EOG's completion strategies to complete 900 DUCs.
What would the break-even be for Bakken oil if all drilling stopped immediately and operators used EOG's completion strategies to re-frack all wells drilled before 2014?
In both scenarios: minimal drilling costs; minimal G&A; minimal change in lease operating costs; -- in other words, the only real cost would be fracking. And the operators would be doing this in this climate:
- unlimited water in the Bakken (compare with the Permian -- remember the original question);
- really, really cheap and really, really lots of available sand;
- low-cost fracking environment;
- an incredibly favorable regulator and legislative climate; see recent pipeline story to see how fast operators get things done in the Bakken (time travel?);
Before I go further, for those that haven't paid attention to the EIA dashboards, here are the links again:
- EIA pdf, Bakken: https://www.eia.gov/petroleum/drilling/pdf/bakken.pdf
- EIA, pdf, Permian: https://www.eia.gov/petroleum/drilling/pdf/permian.pdf
- EIA, pdf, Eagle Ford: https://www.eia.gov/petroleum/drilling/pdf/eagleford.pdf
Look at the production data for the ten wells that came off the confidential list since Thursday last; these are huge wells:
- they were all tested in September, 2019;
- they all started producing in September, 2019
- production data was through the end of January, 2020
- none of them would have had a full September month
- so cumulative production is for less than five months
- cumulative production for these ten non-cherry-picked wells; simply the last ten wells that came off the confidential list
- note: not boe; does not include natural gas; this is only crude oil production;
- file numbers / cumulative crude oil production, all in less than five months:
- 36027: 107K bbls crude oil
- 36026: 130K
- 35821: 134K
- 35820: 139K
- 36146: 232K bbls crude oil -- EOG completion strategies
- 36415: 282K bbls crude oil -- EOG completion strategies
- 36413: 291K bbls crude oil -- EOG completion strategies
- 23958: 178K bbls crude oil
- 35064: 122K bbls crude oil
- 35063: 165K bbls crude oil
EOG is reporting wells that produce 300K bbls of crude oil in less than six months.
By the way, the one DUC among the eleven wells that came off the confidential list:
- 35100, SI/NC, 77K bbls of crude oil in four months, 10 days;
What makes this so hard is this: how do we define "most resilient"?
I'm going to use the EIA dashboards that come out monthly. This should be fascinating. The most recent EIA dashboards are dated "February, 2020" and screenshots can be found here.