Thursday, 22 January 2015

Q: So what happens when oil hits $45 a barrel?

Two lengthy answers here to two simple questions:

  • Q: What happens to fracking, and to  the U.S. economy and beyond, when oil hits $45 a barrel?
  • Q: Is the U.S. economy built on a mountain of shale oil debt?
  • Supplementary Question For You To Ponder: Since virtually all real commodities are also going down, including milk powder, and for somewhat similar reasons, what lessons for our own dairy boom?

Or in other words, in investors’ desperate search for yield has all the Fed’s counterfeit capital been pumped into supplying more commodities, like oil, than the market actually demands? If so, does that make the recent savage surge in oil supply a classic Austrian mountain of malinvestment?

And if so, then what happens next?

U.S. Economy Built on a Mountain of Shale Oil Debt?
Intro, by Ryan McMaken

There's nothing bad about drilling for oil. And there's nothing bad about the fact that the industry has created a lot of jobs. It is problematic however, that the industry is highly leveraged and reliant on easy money policies to keep the exploration and drilling going. Similarly, there was nothing bad about building a lot of housing during the 1990s and 2000s. The problems arose not from the fact that homes were being built, but from the fact that they were built on a mountain of debt based on easy money. The shale oil industry may simply be the next (Austrian) textbook example of malinvestment.

Ben Swann recently interviewed Marin Katusa, author of The Colder War about the shale oil industry.

"A big effect of QE," he says, was that money flooded into the shale sector as people were chasing yield. The result is there is now a "$150 billion of debt in the US shale sector," and if oil prices continue to go down, "There's going to be a lot of defaults." And Katusa worries about the "spillover" into other industries.

"What's going on the US shale sector right now will be bigger than Lehman Brothers." he says.

The Truth Behind the Bakken: A Mathematician’s Take
Guest post by Marin Katusa

Don’t worry, I won’t bore you with differential equations. But I feel a need to talk numbers—but I’ll make it fun and interesting.

With $45 oil upon us, every bobble head has an opinion not only where the price of oil will be, but what will happen to production within the shale sector. Well let’s get the basics out of the way: with a 50% drop in the price of oil, a producer experiences shrinking profits and much lower cash flow.

And in reality, most oil executives, though they wouldn’t dare say it in public, know that half their acreage is uneconomic.

Let’s Start with Cash Flow

Cash flow for oil companies has a direct relationship with the price of oil. I’ve stated for years that not all shale formations are equal—and more important, the economics within a single formation varies depending where in the formation you are and your infrastructure in place.

There is a significant learning curve for exploring and producing (E&P) companies across the different formations, as they all vary—for example, in depth, porosity, and rock type. The more they drill, the more they understand the specific attributes of the particular area.

This learning curve allows the E&P companies to derive the optimal well depth, the number of fractures per well, how much proppant to use, along with the total number of wells to drill.

The math at the end of the day is very simple. Adding up all these variables, we get the production costs; subtracting the cost to produce from the revenue attained from each barrel of production sold generates a positive or negative value.

While it may seem basic, these are the building blocks of determining the economic feasibility.

Below are the break-even prices by shale formation:

The Bakken

Using North Dakota’s infamous Bakken region as an example, we’ll demonstrate that the economics within the same formation can vary substantially.

This variability is especially crucial in a weak oil-price environment. Why? Because at sub-$50 oil, only two counties in the entire Bakken region in North Dakota generate reasonable enough returns for the producer to reinvest in the area.

An acceptable internal rate of return (IRR) of 20% is required on average for further development of a field. Anything less than this, and the field becomes questionable.

Oil wells with 0-10% IRRs are likely to be uneconomic after corporate expenses and interest charges.

Now, it’s an entirely different landscape if you use $75 oil vs. $45 oil per barrel. At $45 oil per barrel, there are currently just over 400 wells that have a 30 day initial production (IP) rate at over 900 bopd and clear the 20% after-tax IRR hurdle in the North Dakota Bakken.

There are 5,400 wells drilled in the Bakken with 30-day IP rates at or greater than 300 bopd, which means roughly 7.5% of the wells drilled meet the after-tax IRR threshold.

The chart below depicts the after-tax IRR for wells producing between 300-1,000 barrels of oil per day, with associated well costs of $7 million, $8 million, and $9 million.

So what happens to the other 92.5% of the wells?

First off, we don’t and won’t own them, because now many are barely economic, and many are uneconomic after all full-cycle costs are factored in.

So what happens to the uneconomic wells? Uneconomic assets lead to impairment charges and write-offs. It’s bad for you as a shareholder if you own companies that will be doing write-downs over the next 12 months.

Write-downs and impairments occur when a company reassesses the value of its land at a lower valuation than is on its previous balance sheet.

More important, there are many debt covenants that will be breached, which will accelerate these write-offs. This will be a disaster for the E&P investor exposed to these types of companies, as they’re extremely detrimental to the total value of the E&P, which in turn crushes the share price.

Below are the breakeven prices required by E&P companies throughout the Bakken in order to generate the expected 20% after-tax IRR. Once again, the chart is broken down by production between 300-1,000 barrels of oil per day and by well costs.

The key here to understand is that using our matrix and seeing the production and cost of the well, you can determine what the 20% after-tax IRR threshold is.

The sweet spots of the Bakken, as we pointed out earlier, make up less than 10% of the Bakken. For example, fewer than 5% of the wells that have had 30-day IP rates at or greater than 300 bopd have produced a 30-day IP of 1,000 bopd and met the 20% after-tax IRR threshold. Using this example, we see from the picture below that these wells are tightly spaced within three counties. Considering that there are over 25 counties that make up the Bakken, we can see that the sweet spots are few and far between at $45 oil.

What does this mean for Bakken producers? Likely this means that most operating outside the extremely small core area shown above in the 1,000+ bopd area are likely losing money on every well drilled at current oil prices.

You see, mathematics does work. And no differential equations needed.

Let’s Use a Real-World Example, Rather Than Theoretical Numbers

I will not to mention the specific name of the company (In my paid newsletter I do mention the peers and which companies are in trouble) I believe is in trouble, even though I have no position (long nor short) in it, we’ll just mention the assets.

This particular company states it has over 100,000 net acres in the Williston Basin, targeting the Bakken and Three Forks. When we looked into its wells and acreage position relative to the rest of North Dakota, we can see this company is one of the outliers in the play. While a portion of its acreage is within McKenzie County (and it likes to remind investors of that), it isn’t in the sweet spot.

This is proven when we model out the company’s well economics using its well cost along with lease operating expenses and production taxes. Comparing its results to the Bakken powerhouse Continental Resources (which has a large acreage position in McKenzie County), it isn’t even a close race. (I have no position in Continental, nor is it recommended in any of our newsletters.)

The economics at $50 oil are poor for both producers, but Continental Resources does generate a positive return, unlike our example company.

It’s noteworthy that Continental can manhandle negotiations with transportation providers due to its significant Bakken Presence (120 million bopd). As such, Continental’s differential to WTI is only $2.50 per barrel. This translates to a reduction of over 70% in transportation expenses relative to the rest of the Bakken producers, which are forced into nearly a $10 differential at current prices.

Impairment Charges and Write-Offs

In my newsletter, I mention our comparisons because you pay for the research. That’s why we’ve labelled the company we’re referring to as “Example Co.” Regardless, we ran the economics on our example company and we expect shareholders of that company to be greatly disappointed.

For example, the company I cannot name has over $150 million in unproven acreage listed as an asset on its balance sheet. Could be true at $95, but not at $45 oil.

The last time these assets were valued, oil was at $95. When the assets are revalued at current prices—which they will have to be—the unproven acreage will be written down to zero based on the economics above. That’s the harsh reality of the current oil market.

A Warning

Companies that have made their bets on plays extending away from the core areas are likely the first candidates to have to take impairments and property write-downs. The Bakken is very real—and we believe in its future. However, we used the Bakken because it’s a good example of companies straying from the core acreage which generates the most reliable economics. Reductions in drilling and service costs will not be enough to save the high-cost producers in the current oil market on the outskirts of the big area plays.

Their wells do not have the same firepower in terms of raw production volumes, nor do these companies have the intellectual capital associated with drilling hundreds of wells in a single formation. Additionally, they will always be last to the infrastructure party, waiting to be tied into the pipeline and always being forced to take a worse differential then the likes of the Continental Resources in the Bakken.

Marin Katusa is Chief Energy Investment Strategist for the Casey Daily Despatch, where his post first appeared.

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