We are proud to introduce a new shaleism to the United States shale dictionary, hurdle, as in U.S. shale production is now facing increased hurdle rates.
Hurdle(s) can be defined as oil prices, gas prices, domestic energy policy, steel tariffs, falling well productivity, increasing GOR and associated gas as a percentage of the production stream, declining drilling inventory, debt, frac source water, earthquakes, produced water bubbling out of the ground, interest rates... you name it; is been a 440 high hurdle race since 2009, round and round we go. But now at least, we have a name for it.
By shear miracle Rystad has just now apparently discovered some of these hurdles, like interest expense on long term debt and dividend costs and decided to use them in their stupid breakeven metric. I've been using both for the past three years. They've been hurdes for a long time and not including them was deceptive.
You may click to read the article, above.
We have previously posted about Rystad's new breakeven estimates for U.S. shale plays but this graph is just out today and we feel it is newsworthy. I don't agree with its cost categories; for instance I don't know what "wellhead" means, exactly. If its net oil price at the WH... after transportation and marketing, royalty deducts, severance and property taxes and OPEX, including surface and downhole maintenance, I am good with that number. Well, I would actually axe the discounted PV18 deduction and put that $4.50 per incremental BO over in the wellhead category. You cannot BELIEVE what it costs to wash an 18,000 foot lateral out with CT, or replace an ESP. Yikes. People always leave out well intervention costs, as though well maintenace does not count because its not fixed. Pfttttt.
Corporate overhead I am good with. CEO's gotta get paid regardless of falling production. These incremental per BO costs have gone up over the years as production levels have plateaued. I am really good with interest expense on borrowed capital at $3.00 per BO; I have done the math on that. FANG and DVN, just as example, owe $20 B in long term debt, just the two of them.
I am wowed by the dividend expense per incremental BO Rystad comes up with but on a BO basis it looks true using the same two examples, above. Its tricky figuring dividend expense based on shares outstanding, etc. but I think I got it. Rystad is smarter than I am. Why shaleco's are paying the dividends they do I have no clue. I guess that is why they have to borrow money to pay them. Imagine that, for a minute. To create the illusion that you are profitable, you must borrow money to pay dividends to investors.
Only in the U.S. shale sector.
All and all I am really good with the $62 figure Rystad has come up with and nobody is making jack shit right now in the shale oil patch. NOBODY. If Exxon says it is, its lying, and the Department of Energy suggesting shale oil will actually "thrive" at $50 is, well, remarkable. Its the government speaking. Since when does anybody believe it when the government comes calling to say, "hello, I am here to help."
By the way, this breakeven number has nothing to do with drilling and completing new wells, $62 is what it costs to get a gross barrel of oil out of the ground no matter how old the well is.
So, if oil goes to $73, and if a shaleco can make $10 a barrel net back, after all costs, it takes 1,000,000 barrels of oil to payback a $10 million dollar Midland Basin Lo. Spraberry well (https://www.afeleaks.com/p/welcome-to-afe-leaks). Find me 100 of those kinds of wells in that sub-basin drilled in the past 12 years.
By the way this is NOT "all-in" cash flow breakeven. Not by a long shot. Rystad is grossly mistaken about that. The two entities I looked at alone at $20B of long term debt, how is that going to get paid back when you make NO money? How about well retirement costs for 8,000 wells both FANG and Devon have to plug? How do you pay that back when you make no money? There is $140B of long term in the Permian, and it has 62,000 wells to plug and abandoned. Those are both really high hurdles that Rystad ignores.
All in means all in, including closing the doors one day with no liabilities, all your debts paid in full. How come everybody always forgets those costs?
I want you to get smarter than these guys running this shit show. Energy is everything. You gotta vote for folks that tell the truth.
A word about OPEX, or incremental lift costs per BO, included in breakeven estimates.
Laura Freeman is a smart PE from Houston and made this observation several years ago when looking at shale oil production for sale on the open market. OPEX is the best venue the shale sector has for funky arithmetic used to enhance marketability or lie about in-house economics. They're all over the place with it.
Shale R Us LLC will build a water gathering system for $59 MM to send a bunch of water from a big block of acreage to a 3rd party SWD well, then report only the SWD injection costs per BW in OPEX. The $59 MM disappears. I remember 5 years ago Scott Sheffield claiming his OPEX was $2.60 per incremental BO and his stock went nuts, until he corrected his statement to say, per incremental BOE.
Lots of ANALysts focus on OPEX that is fixed every month, like electricity, chemicals, liability insurance, etc. etc. and non-re0ccuring maintenance costs on a commingled lease/unit tank battery, for instance, or down hole repairs on a well, is expenseable and gets shoved over into drilling IDC (intangible drilling costs), or places other than operating costs. Good people send me lease operating statements (LOE's) occassionally and ask me questions I don't have the answers to. This non-GAPP stuff the shale sector does is amazing.
Shit happens in the oilfield about every 39 seconds and its got to be fixed. The money to fix it comes for production revenue so maintenance is a cost to extract the barrel. How you make these costs disappear I don't know, but they do.
This snake looking thing has just been fished out of the hole at 9,000 feet. Its coming up thru the slips on the rig floor now. Its the power band on an ESP in the Permian. The ESP itself cost $285K to install including surface VFD stuff for all the electricity required to move oil and water out of the hole via the ESP. The well I seem to recall had a cummprod of 285K BO and was making 160 BOPD with a WOR of 25%. It was a stinking mess to fish. Total costs with rentals, rig costs, tubing rentals, fishing tools, consulting fees, etc. etc. was $150K. Shale R Us, LLC then washed the well out with coiled tubing: $100K. Replaced some tubing that did not test: $50K and then had to replace the entire ESP, brand new, about $235K. Est. total well intervention costs: $535K. All non re-occuring.
This well went on to make 100K BO on the 2nd ESP over 6 years before pressure depletion and fluid conductivity became a problem and they put it on rod lift. Incremental DH maintenance costs over the period was then $5.35 per BO that should have shown up on LOE's to the 8/8ths WI, but simply disappeared into the vast accounting unknown. How this expense was accounted for changed the entire well picture, IRR, ROI, everything.
This stuff happens every day. Everywhere. I've heard of casing parts on producing wells that cost over $1.5MM to tie back together. Thats a cost of getting oil out of the ground, after D&C costs. Its part of the breakeven metric. Just like paying debt back. Gasp!
So when looking at breakeven prices look really hard at OPEX costs and make sure they look right. If the well is making 80% water and maintenance costs are included, those OPEX costs have to be minumum $15-$18. Produced water costs are killing those guys out there.
Want to be an oil operator? Go buy some liability insurance for operating a lease, protection against personal injury, spills down the lease road, a cow falling in the cellar, teenagers smoking on a tank battery that blows up. You won't BE*LIEVE what that costs !
We're smaller potatoes up here in Appalachia--but the same realities apply. "Good" new Utica wells churn out 10 to 12 loads of "oil" per day...for a couple months. Then within six months they are down to two loads per day and still declining. And take it from sources that know: within the last week drilling plans have changed drastically across Appalachia. Chris Wright might not know this...but we actually can't make money at $55 oil. We might break even at $62 depending on the royalty. But that's using casing stacked in the yard. God knows where steel prices are headed. Gird the loins boys.
95% of the American public that reads this Hart dung heap will do this:
500,000 BO in 10 months, WOW ! 500,000 BO X $61 NYMEX (oilprice.com) = $30,500,000 !! These shale dudes are killing it! They need a windfall profits tax or Trump can take the price oil down to $45 NYMEX, the bastards. I'm still paying $3.35...oil companies suck!
But wait a minute, Rystad now says at $61 the shale sector is losing a buck fifty per BO. That can't be right! Nobody is that stoopid to drill a 14,000 foot lateral in the Midland Basin, requiring a protective string of casing across the San Andres, for $10 million dollars (afeleaks.com) that won't ever pay out drilling and completion costs, are they?!!
Well... yeah.
These two (2) "big Dean" wells will have to make 1,000,000 BO each at $72.50 NYMEX just to pay out, if Rystad is right about breakeven prices.
How many Dean bench wells drilled in the Midland Basin since 2016 (over 1,400) are on an EUR track to make 500,000 BO, much less 1MM BO in their lifetime?
You can count 'em on one hand.
Nice photograph though. West Texas sunsets can be really cool.