With the recent free-fall in the price of oil, an increasingly asked question is: What impact will these lower prices have on America's production of shale oil?
If we just look at the income statements that shale companies file with the SEC, it's difficult to determine if they are engaged in a profitable enterprise. Intuition tells us something is probably wrong, and smart people we trust mutter about cash flow and talk about a Ponzi scheme, but how can we know for sure?
Can shale oil be profitable at all? If so, at what price? And under what conditions?
I will deconstruct all this here and then put it back together.
A shale well consists of a vertical shaft that drives down into the earth to get to the right geological layer where the oil is located. Then the shaft bends 90 degrees, and extends horizontally for thousands of feet. It is in the horizontal section where the magic takes place. At intervals along the horizontal section, the “frac stages” happen, each of which fracture the surrounding rock to release the oil locked inside the rock.
Constructing a shale well happens in two stages. First both the vertical and horizontal sections of the well are drilled, and that costs around $3.5-$4 million taking perhaps 20 days. Then, the well is “completed” – this is where the frac stages are placed. Each frac stage costs around $70k, and there are often 20 or more frac stages per well. The entire completion process costs around $4M. Once completed, the well starts producing oil and gas.
The initial production (IP) of the well is a critical number for estimating the total amount of oil likely to be produced over the lifetime of the well (“Estimated Ultimate Recovery” = EUR), along with the expected decline rate. While the EUR is a theoretical number and assumes a recovery time of 10-30 years, from a practical standpoint, companies need to recoup the costs of drilling the well within 3 years.
Shale drilling has dramatically improved over the past five years. Horizontal lengths have doubled, upgraded drill rigs result in fewer breakdowns and faster drilling speeds, pad drilling has eliminated the downtime required to move the drill.
Today's wells (vs wells drilled in 2008-2011) have horizontal sections twice as long, with three times as many frac stages, with closer frac groupings, and the wells are drilled in about half the time. This results in wells that produce about twice as much, and take half the time to drill.
Regions & Geography
There are three primary geographical regions where shale oil drilling takes place: Bakken, Eagle Ford, and the Permian Basin. Total production in these three areas: 4.6 mbpd, or 92% of shale-region oil production in the U.S.
Shale regions provide all of the growth in US domestic oil production.
Of these three areas, Bakken and Eagle Ford are the two primary oil shale areas, and these are the areas on which I will focus my analysis. Many wells drilled in the Permian are vertical wells, so I will exclude this area:
The decline rate of shale wells is almost the defining characteristic of the shale plays. Decline rates vary by region. On average, Eagle Ford wells have a 62% first year decline rate, Bakken wells have a 54% rate, and Permian wells decline at a 33% rate. The rapid decline rates mean that the production from shale will drop off fairly dramatically when drilling ceases – about 16% per quarter in Bakken, and faster in Eagle Ford.
If a well's IP (initial production) is 1000 bbl/day, a 54% decline rate means that one year later, that well will only be producing 460 bbl/day. 54% of the well's production is just gone. This is very different from standard vertical wells, whose decline rates are in the 5-7% per year range. Here is a look at changes in the decline rates of the different regions over time:
To understand the economics of shale, we view company performance through the lens of accounting. A good accountant is a historian, honestly assessing the success or failure of a particular venture. (A bad accountant – the ones at Enron, for example – are fiction writers).
So first, some accounting terms:
Revenues: barrels of oil sold x the price of oil. Its pretty simple.
Capex: capital expenditures. In shale, this is all the costs involved in drilling and completing wells, purchasing equipment, and other long-lived assets required to run the business.
Opex: operating expenses. In shale, this includes all the other expenses the business has:
collection & transportation costs: getting the oil to market
SG&A: sales, general & administrative costs – including paying the CEO
interest expense: for bonds, bank loans, preferred stock dividends
lease operations expense: actually pulling the oil out of the ground – insurance, repairs, maintenance, pumping costs, etc
depreciation/depletion: a fraction of capex – it should be the decline rate of each well multiplied by the original cost to drill & complete.
Income = revenues – opex – depreciation
here is where the funny stuff happens. If you want your company to look profitable, you will tell your accountant to write a work of fiction rather than be a historian. Instead of having her use your actual 54%/year decline rate, you will instead tell her to use, say, 10%.
Key concept: understating depreciation increases reported profits. Why would you do this? Well, if you wanted to sell your shale properties to a greater fool, you probably want to look profitable in the meantime. Or if you wanted to get a bank loan, or sell junk bonds, you probably want to look profitable too. Unless your lender truly understands decline rates and how they apply to the depletion you report on your income statement, they won't know any better.
EBITDA: revenues – opex
Simply put, this is “earnings before accounting/depletion fraud.”
This is the number I use to study profitability in the shale world. I can then apply my own depreciation based on Capex and decline rates and figure out for myself how the business is really doing.
All right, armed with your new degree in shale accounting, let's look at a simple fictional example. The One-Well Shale Company drills and completes a Bakken shale well costing $8M, with an IP of 500 bbl/day, 1st year production: 182k bbl, decline rate 56%. These are current average numbers in the Bakken shale region:
The income statement shows that even with (somewhat) honest accounting, we made money! Ok, not a lot, but at least we're in the black. And doesn't year #1 look fantastic? That's because my depreciation is a simple 33% per year.
Some points to consider. Most of the opex costs are fixed, not variable. That's what causes problems: shale oil production declines rapidly over time, yet the overhead remains largely the same. In reality, production taxes would decline, but my simple example didn't do that.
I picked these expense numbers from OAS, an actual (high cost) shale producer; opex for OAS is $44/bbl of current OAS production. And I also set oil to be $100/bbl. With $100 oil, everything looks good.
Note I tried to be an honest accountant, and pay for the well over 3 years, although my depletion schedule was straight line. If I were more clever I'd have depreciated it based on the actual decline rate of the well.
Now lets drop the oil price to $57/bbl and see what happens to One-Well Shale:
Even on an EBITDA basis (i.e. we pretend we get the well drilled for free) we're losing money by year 2. And on an ROI basis, we've lost $12M by the end of year 3! Quick, sell the well to someone who doesn't understand decline rates – or perhaps we could create a royalty company and spin it off, retaining 5% ownership to pretend we've still got skin in the game. But who would fall for such a scam?
Shale producers don't want to expose themselves to bouncing oil prices – they have fixed costs, and so they'd prefer to have fixed revenues too. So they typically engage in oil price hedging to eliminate one big variable from their business plan. One-Well Shale certainly had big problems when oil dropped to $57/bbl; if One-Well had engaged in hedging, it might have been able to ride out the low prices and not gone bankrupt in Year 2.
There are many types of hedges available – our friendly banking establishment stands ready to provide all sorts of tools to shale companies to help them out. For a fee, of course. I'll start with the simple ones, and gradually get more complicated.
Swaps: buyer locks in a fixed price for oil. No upside, complete downside protection – you know exactly what price you'll get, and on what date. Low cost. This is why futures markets exist. Speculators take the risk, and companies get to operate in a more predictable world.
Puts: complete downside protection, unlimited upside. The higher the floor and the longer the date, the higher the cost. Puts are relatively expensive.
Collars: complete downside protection, lower cost, limited upside. Buyer writes a call, and buys a put. Upside available up to the call strike price, and the call helps make the put less expensive. As with the standard put, the higher the put's strike price and the farther out the date, the more expensive it is.
3-Way Collars: limited downside protection, limited upside, usually free cost. Buyer writes a call and a put, and buys another put. This complicated beast generally ends up being free, but only is good for maybe $10-$15 of coverage. It's probably a banker's delight. It sure sounds salacious enough.
Most producers choose swaps. They have the virtue of being simple. But when you look at the company hedge book, which they report in their 10-Q, understanding just what sort of coverage they have is quite important. Swaps provide perfect coverage, while 3-way collars only protect against a fraction of the drop we've just experienced. And its important to match up the number of barrels of coverage to the oil production, to see the percentage of coverage the company has in place. A survey of shale companies shows a range of from 20-60% coverage, at an oil price of about 90.
Hedges can be cashed in at any time. A company with a trader as a CEO, or one that needs to raise cash to stay in business might well decide to “go naked” and take their chances with market oil prices and close out their swaps, or puts, or collars, etc. One company did this just recently. CLR sold their entire hedge book in Q3 2014, raking in a cool $420 million. They did this (from what I can tell) when oil was trading at about $77 – about $20/bbl too early. They left $500 million on the table. Maybe more. And now they're fully exposed to $57 oil.
Shale History & Accumulated Debt
As mentioned earlier, shale drilling is both cheaper and a lot more productive than it was when the whole effort first started back in 2008. Wells today are cheaper to drill and complete, and more productive. Think: twice as productive, and/or half as expensive.
Unfortunately a lot of companies did a lot of drilling, and took on a whole lot of debt to finance those early wells, most of which aren't producing very much today. Many companies I surveyed spent $5-$10 over their total lifespan to get $1 in fraud-free EBITDA today. 90% of that money they spent is just gone.
Scroll back and look at One-Well Shale. With oil at $100 using 2014 technology, One-Well Shale spent $8M and generated $10.8M in EBITDA for its first year! That's a ratio of 0.8:1. The companies I looked at have ratios of 5-10:1. Roughly speaking, they have taken on debt and spent the equivalent of $40-$80M over their lifetimes, to generate EBITDA of $10.8M this year – and that's with $100 oil! They are carrying massive debt loads, and have very little production to show for it.
One-Well Shale's “honest income statement” shows that 2014 shale technology is economical at $100 oil, even with a relatively high cost producer's cost structure like OAS, and just assuming “average well production” (an IP of 500 is average in the Bakken) and so I believe shale will bounce back if and when oil prices return to $100/bbl. However, the existing shale drillers have so much debt, and have so little production to show for it, I believe that most of them will not survive. Think dotcom, followed by dotcom washout. Amazon.com still exists, but all the rest are long since dead.
Understand, I'm deliberately not addressing how long-lived the shale resource is, I am just answering the question, at what price is it economical, using (relatively) fraud-free accounting methods. The answer is, it depends on the company's cost structure, and also the IP of the well. An average well (IP=500) at a company with a reasonably low cost structure ($20/bbl) is break-even at about $62/bbl.
If you want to look at some shale drillers, contrast Goodrich Petroleum (GDP) with Continetal Resources (CLR). Total Debt/EBITDA (my metric for “what production did you get for your money”) in Q3 2014: CLR=2.1, GDP=9.9. Total Debt/Revenues: CLR=1.5, GDP=7.6.
I believe CLR may be one of the survivors, depending on how long they have to survive with $57 oil. Their cost to produce is about $20/bbl, which is quite low.
GDP's Total Debt/Revs ratio implies that after spending $7.60 over their corporate lifetime, they now have $1 of current production – and at $57/bbl, they lose money on every well, since their opex costs are $71/bbl. And that production decays to $0.44 next year. Once the bank pulls their credit line, and they've sold their hedge book, they're done like dinner.
The accounting journey we've taken here shows that real concerns exist about the near-term solvency of America's shale oil drillers now that oil has plummeted by nearly 40% in the past 3 months. How bad is the shakeout likely to be?
In Part 2: The Destruction That Awaits, we scope out the timing and the extent to which production will fall, even at the wells run by the surviving drillers. But the sad reality is, the "shale miracle" has numerous ponzi elements, and with today's suddenly lower oil price, they are in the process of imploding.