For years, we’ve been warning here at PeakProsperity.com that the economics of the US ‘shale revolution’ were suspect. Namely, that they’ve only been made possible by the new era of ‘expensive’ oil (an average oil price of between $80-$100 per barrel). We’ve argued that many players in the shale industry simply wouldn’t be able to operate profitably at lower prices.
Well, with oil prices now suddenly sub-$60 per barrel, we’re about to find out.
Using the traditional corporate income statement, it is difficult to determine if shale drilling companies make money. There are a lot of moving parts, some deliberate obfuscation at some companies, and the massive decline rates make analysis difficult – since so much of reported profitability depends on assumptions made regarding depreciation and depletion.
So, can shale oil be profitable? If so, at what price? And under what conditions?
I try to deconstruct all this here.
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 5000-10000 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 $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 20-30 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 a new 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 more 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. However at the same time, many of the best spots have already been drilled, so the significant improvements in drilling efficiency have only been able to increase per-well production by a modest amount – perhaps 7%.
Regions, Geography, Decline Rates
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 US. Shale regions provide all the growth in US domestic oil production.
Of these three areas, Bakken and Eagle Ford are the most productive oil shale areas, and of these two regions, I’ve selected the Bakken for a more detailed analysis.
The decline rate of shale is the defining characteristic of a shale well, and a shale region. Decline rates vary by region. On average, the Eagle Ford region has a 62% decline rate, the Bakken region overall has a 54% rate, and the Permian region (many wells there are not horizontal wells) declines at a 33% rate.
Individual wells decline more rapidly, and most steeply in their first year of production: Bakken wells decline at a 72% rate for the first year, and then more slowly in the following years. Many Permian wells are vertical wells, and so their decline rates are much more gradual, accounting for the slower Permian region decline rate.
If a well’s IP (initial production) is 1000 bbl/day, a 72% well decline rate means that one year later, that well will only be producing 280 bbl/day. With the IP=1000, the first year production is 205k bbls, and the EUR (lifetime theoretical) is 650k bbls. Here is a look at changes in the decline rates of the different regions over time. [source: http://www.eia.gov/petroleum/drilling/]
In order to acquire the right to drill on a particular patch of land, the drilling company must purchase these rights from the landowner, and/or another drilling company that has already bought the rights. In the most productive areas such as the Bakken shale, rights are expensive, with recent transactions priced around $10k per acre.
After a fair amount of experimentation, drillers have determined they can put from 1-3 wells on one square mile before the wells start interfering with each other. There are 640 acres per square mile, therefore drilling rights are about $6.4M/square mile. This makes land costs to be around $2M-$6M per well.
Before you can drill, you have to get the rights. Typically, you go into debt in order to buy the rights, then you start drilling to recoup your investment and pay the interest costs on all that debt. Maybe you can even sell those rights to someone else for a profit. That’s the ponzi aspect of shale: buying land rights with junk bond financing for $2000/acre, and selling those right off to an unsuspecting oil major for $10,000/acre.
Rights only last from 5-10 years. Failure to drill = wasted money.
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 – at Enron, for example – is a fiction writer).
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, land drilling rights, and other long-lived assets required to run the business.
- Opex: operating expenses. In shale, this includes all the other expenses the business has:
- well operations: insurance, repairs, maintenance, pumping costs, etc
- G&A: general & administrative costs – including paying the CEO
- interest expense: for bonds, bank loans, preferred stock dividends
- transport: getting the oil to market
- royalties: paying the landowner a chunk of your revenues
- production taxes: paying the state a chunk of your revenues
- depreciation/depletion: a fraction of capex – it should be the decline rate of each well multiplied by the cost of the land plus the 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 72% well 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. Banks are more clever than junk bond buyers, however; they use ratios that depend on EBITDA, not phony “profits.”
- 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 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 hypothetical One-Well Shale Company obtains property for $10k/acre, then drills and completes a Bakken shale well costing $9M, with an IP of 500 bbl/day, 1st year production: 102k bbl, decline rate 72%. Further, we assume an eventual 3 wells per square mile, and an oil price of $99/bbl.
The income statement shows that with honest accounting, we are barely profitable just looking at the 3-year P&L statement. The price I selected wasn’t an accident – I searched for the break-even price and found it at around $99/bbl.
However, will this well at $99/bbl ever make back its drilling costs? It won’t, since in the following years, the “fixed costs” for the company will be a heavier and heavier burden on the well whose production declines every year. Likely, $99/bbl is even too low. We can call it a “best case scenario” – only if we assume One Well Shale sells the well to someone else for $986k (the remaining depreciation) at the end of year 3.
What’s more, companies have already spent huge sums accumulating land, on which they’ve drilled a relatively smaller number of wells, so this “One-Well” shale company is definitely fictional. Take OAS, which has 468 wells in production (45k bbl/day = 98 bbl/well) and 779 square miles of land they’ve bought for $1.8 billion. That’s only 0.6 wells per square mile. However, they’ve already spent the money for the land, so from a “cash flow basis”, they don’t really count the land cost when answering the question: “do I want to drill a well here or not.” At this point, money to buy the land is gone, so from a corporate survival standpoint, all they ask is, “if I drop a well, will it pay me back in 3 years?” And in the current environment, they probably only look at year 1 when making this analysis.
But from an overall economic analysis of shale profitability over the longer term, land cost really is an important factor, so we include it in our accounting. If we were to be hard-nosed, we would probably assume a “wells per sq mile” of 0.6, since that’s the “actual debt burden” on the real drillers like OAS.
Now lets drop the oil price to $55/bbl and see what happens to One-Well Shale.
Its a sea of red ink. Clearly this well loses money. It cost $9M to drill, and we get back $2M in EBITDA at the end of year 1, the best year for the well. By the end of year 3, EBITDA is negative. It is definitely not worthwhile to drill this well, not even if we assume the land is free.
This represents the average well in the Bakken. At current prices, the average well loses money, no matter how you slice it. So how will this affect capex budgets in 2015? Here’s one data point from OAS, a company for whom 100% of their production comes from the Bakken: they are cutting their capex budget in half, choosing only to drill in their better properties. [Source: an awesome, detailed, fact-filled investor document that Google located for me – one wonders if they meant to release it to the public: http://www.oasispetroleum.com/wp-content/uploads/2014/12/2014-12-OAS-IR-PresentationvFINAL.pdf]
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 $55/bbl; if One-Well had engaged in hedging, it might have been able to ride out the low prices at least for a time.
There are many types of hedges available – our friendly banking establishment stands ready to provide all sorts of financial 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 sounds vaguely salacious.
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.
Looking at our favorite Bakken company OAS, we see their hedge book below, helpfully provided in their investor document. It looks complicated. So we just look for key words: first, what type of hedges? Swaps, puts, & 2-way collars. Great, that’s 100% coverage. Second, how much production do they represent? 1H 2015: 32k bbl day, and 2H 2015: 15k bbl/day. Let’s assume OAS keeps production steady at 45k bbl/day. That’s a 71% coverage for 1H 2015, and a 33% coverage for 2H 2015 at “around” $90/bbl. Looks like they’ll be mostly ok for 1H 2015, but for 2H 2015 they will definitely be losing money if oil stays at $55/bbl.
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 today might well decide to “go naked” and take their chances with market oil prices and close out their positions. 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 $55 oil. Factoid: $420 million will fund one month of 3Q capex at CLR.
Shale History & Accumulated Debt
One-Well Shale’s “honest income statement” shows that 2014 shale technology is economical at $100 oil, assuming “average well production” – an IP of 500 is average in the Bakken.
Of course, shale companies must survive today, with oil at $55/bbl. Let’s assume OAS gets serious, and drills only in their really hot areas. Viewed through the One Well Shale P&L statement, if I set the IP=750, and I set the oil price to $87/bbl, cash flow is $9M in the first year and a 3-year ROI of 67%. Through 1H 2015, OAS will be all right if they can just drill their best opportunities, and rely on their hedge book to keep them afloat.
That’s not the the same thing as asking if the wells they drill will be “profitable long term” since that $87/bbl price obtained via hedges will only last through 1H 2015. Once the hedges run out, those IP=750 wells will be just barely above break-even (after 3 years!) at $55/bbl. But for the moment, OAS can stay above water.
I’m deliberately avoiding the question of how long-lived the shale resource is. I am just answering the question: what is the break-even oil price for drilling a Bakken shale well. The answer is, with an average well (IP=500) at a company with an average cost structure is long-term break-even at about $99/bbl, best case, assuming 3 wells per square mile and a property cost of $10k/acre.
Bottom line: the average US shale oil well is uneconomical even with hedging in place, since most hedging is around $90/bbl and the break-even is $99/bbl.
The Risk We Now Face
In Part 2: The Destruction That Awaits, we delve into the important question of the longevity of shale oil supply. The projections we can make from the latest data are quite frightening.
As is the massive impact today’s oil prices will have on the shale industry should they persist. Simply put, if oil prices stay at $55/bbl, we will eventually lose the vast bulk of US shale oil production, simply because perhaps 3/4 of even Bakken shale is just not economical at that price.
And this prediction assumes the economy continues along as it has for the past several years. Should there be a serious economic contraction and/or a tightening of the credit markets, and the declines hit harder, many fewer shale drillers will be able to find any sort of funding, property sales will be fewer and for lower prices, and a lot more shale drillers will go bankrupt – and recoveries on those bankruptcies will be lower. Knock-on effects will hose the banks providing credit lines, vendors that provided services to companies and were not paid, and pension (and bond) funds that bought the junk bonds that are now worth pennies on the dollar. All of this will simply worsen the carnage to the shale sector.