In last week’s Energy Letter, I discussed my recent trip to the Bakken, highlighting the region’s top oil producers. Today I will drill down in more depth and evaluate these companies’  fundamentals.

The Bakken formation, which is part of the Williston Basin, first produced oil over 60 years ago. It was on North Dakota farmer Henry Bakken’s farm in 1953 that Amerada Petroleum — later acquired by Hess (NYSE: HES) — discovered oil at a depth of about 10,000 feet.

There are billions of barrels of oil in the Bakken formation, but the crude is trapped inside a fine-grained rock called shale. This shale has high porosity, which means it has lots of tiny spaces that hold the oil and gas. But the permeability of the rock is very low. In other words, the rock holds a lot of oil, but it doesn’t flow out readily. Thus, 50 years after the discovery of oil in the Bakken, North Dakota was still a minor producer at less than 100,000 barrels per day.

That would change dramatically with the marriage of two technologies.

The technique of hydraulic fracturing, or “fracking” had been around since the late 1940s and has been used extensively to promote higher production rates from oil and gas wells across traditional production regions like Texas and Oklahoma. Fracking involves pumping water, chemicals and a proppant down an oil or gas well under high pressure to break open channels (fractures) in the reservoir rock trapping the deposit. The proppant is a granular material like sand designed to hold those channels open, allowing the oil (or natural gas) to flow to the well bore.

Hydraulic fracturing rectified the permeability issue. But there were wells being fracked in North Dakota in the 1950s. Why did it take another 50+ years before oil production took off in the state?

There are expenses involved in fracking a well, so the increase in oil production has to make the expense worthwhile. But the Bakken is only 100-150 feet thick. You might imagine that if it were thousands of feet thick you could frack many times at widely-spaced vertical intervals. However, that wouldn’t work in a formation that is under 150 feet thick. If the fractures are too close together you get diminishing returns. You don’t want the fractures from one stage to overlap another stage. So, a vertical well in the Bakken might have a single frac stage, which would increase oil production but not dramatically so.

Like fracking, horizontal drilling was invented decades ago, and has been widely used in the oil and gas industry since the 1980s. As its name implies, horizontal drilling involves drilling down to an oil or gas deposit and then turning the drill horizontal to the formation to access more of the deposit. These horizontal “laterals” can be 5,000 to 10,000 feet in length. So now instead of a well being able to access maybe 130 feet of the Bakken Shale, a single well could access more than 50 times this distance.

Source: American Oil & Gas Historical Society

But it was the combination of these two decades-old techniques that inaugurated North Dakota’s shale oil boom. Because fracking a single stage costs much less than drilling a well, adding stages to a horizontal well drove down the cost to produce each barrel of oil. A 2009 filing by Brigham Exploration — later acquired by Statoil (NYSE: STO) — demonstrates how oil well economics improved as more frac stages were introduced to horizontal wells:

Well economics were improving at the same time that crude oil prices were skyrocketing, and that was the prescription for the shale oil boom that would last until 2014. Of course this created huge incentives for numerous players to do whatever it took to get in on the action. Many were highly leveraged, and when oil prices came crashing down found themselves in financial trouble.

So where do things stand today? In the last Energy Letter, I listed the current top 10 oil producers in the Bakken, but didn’t provide a lot of context for their financial metrics. In today’s article, I am going to peel the onion a few more layers.

Let’s start by looking at the top Bakken producers. In June 2015, the top 20 Bakken oil producers were responsible for 88.5% of the 36.3 million barrels of oil produced in North Dakota. Of the top 20 producers, 17 were publicly traded entities. For completeness, the three privately held companies in the top 20 were Slawson Exploration (#13), Petro-Hunt (#15), and Zavanna (#19).

ExxonMobil (NYSE: XOM) at #4 and Statoil at #7 are huge integrated companies that derive a small percentage of their overall income from the Bakken. So I removed those from the list. Note that there are many other companies listed with substantial operations outside of the Bakken, but ExxonMobil and Statoil not only do substantial drilling elsewhere but also have refining, petrochemicals and midstream businesses.

The rest of the top Bakken producers have varying degrees of exposure to the region. Oasis Petroleum (NYSE: OAS), for example, drills only in the Williston Basin. ConocoPhillips (NYSE: COP), Hess (NYSE: HES) and Marathon Oil (NYSE: MRO) are much less dependent on the Bakken (but more so than ExxonMobil).

Culling the list leaves the following 15 producers, sorted by oil production volume in North Dakota. Note that ConocoPhillips operates here as Burlington Resources, which it acquired in 2006. Halcon Resources (NYSE: HK) operates as its wholly owned subsidiary HRC Operating, LLC.

• EV = Enterprise Value in billions as of Oct. 16
• EBITDA = Earnings before interest, tax, depreciation and amortization for the trailing 12 months (TTM), in billions
• Debt/EBITDA = Net debt at the end of Q2 divided by TTM EBITDA
• Oil Eq. = Oil production in June 2015 in barrels of oil equivalent per day (BOED)
• Oil% = Percentage of overall production that was oil
• Active Wells = number of producing wells in North Dakota
• BOED/Well = average barrels of oil equivalent per well
• Prod Cost = Average cost to produce a BOE in all regions (not North Dakota exclusively)

These top 15 producers on average have an enterprise value of $20.6 billion (which is skewed by a few giants; the median EV is $9 billion), an EV/EBITDA of 4.8, a debt/EBITDA of 2, and  Bakken production in June of over 71,000 barrels of oil equivalent per day — with oil accounting for 82%. The oil fraction is high relative to other major shale plays. The average well produced 145 BOED, and the top Bakken producers had a global average production cost of $13.85 per BOE (not including finding, development, administrative or debt service expenses).

Note that because the cost of production isn’t specific to the Bakken, some companies show a higher cost of production because they may have costlier deepwater or overseas wells.  

There are several items of interest in the table. One is that Oxy has the worst average production numbers per well. While its high cost of production could be partially explained by higher cost non-Bakken operations, its Bakken costs are likely relatively high as the result of the low production per well. Interestingly, Occidental just announced the sale of its entire Bakken acreage and plans to exit the region because production costs are so much higher than its Permian Basin operations.

The most productive wells in the region belong to QEP Resources (NYSE: QEP) and the Conservative Portfolio recommendation ConocoPhillips, with each producing on average more than 200 BOED — about triple the rate of Oxy’s wells.

Whiting (NYSE: WLL) is now the most prolific oil producer in the Bakken following its acquisition of Kodiak Oil & Gas, but the quest to become #1 has generated a lot of debt. Whiting, Halcon Resources and Triangle Petroleum (NYSE: TPLM) all have debt/EBITDA ratios above 3, which places these companies at higher risk of bankruptcy should oil prices remain low.

Should bankruptcy take out some of the more highly-leveraged players or if the threat of it forces a sale, EOG Resources (NYSE: EOG) — one of the best if not the best shale oil producer in the country — would be among the best-positioned players to scoop up the assets. Growth Portfolio recommendation EOG is the only company on the list with a debt/EBITDA ratio below 1. EOG. with its low-cost, high-return wells in the Permian and the Eagle Ford, also happens to be one of the few companies on the list with an overall production cost of less than $10/BOE.

Oasis has a cost of production near the other end of the scale. Its $17.84/BOE is especially high considering that all of its production is in the Bakken. The high cost can be largely explained by the relatively low average production rate of 102 BOED per well, the result of drilling mostly outside the Bakken’s sweet spots.

Growth portfolio recommendation WPX Energy (NYSE: WPX) receives high marks for its level of debt, productivity per well and cost of production — while trading at one of the lowest EV/EBITDA multiples on the list. Incidentally, WPX Energy was also deemed to be undervalued in last month’s deep dive on natural gas producers.

On the basis of this screen, I think WPX Energy stands above all the others. EOG would be my second choice on the basis of this screen. I consider it the best shale driller overall, albeit one priced at a significant premium to WPX. Enerplus (NYSE: ERF) also looks good on this screen, but I don’t yet know enough about this Canadian producer to recommend it.

I would steer clear of the companies with high debt as well as those with low production per well. It is certainly possible that in some cases a company will make up for its Bakken shortcomings with production in other regions, but I would continue to avoid companies like Whiting with a lot of Bakken production financed by a lot of debt.

Although the Bakken remains a key oil-producing shale basin, it has suffered more from plunging oil prices than the Permian and the Eagle Ford over the last year. Those Texas basins are much closer to the Gulf Coast’s many large refineries and as a consequence enjoy lower shipping costs, along with the advantages of operating in a traditional oil-producing region plenty of legacy infrastructure.

The Bakken wells also tend to offer lower return profiles than the shale ones in Texas exploiting thicker formations, another factor that has weighed on capital spending in the region.

Many operators still drilling in the Bakken are also highly leveraged, giving them less financial flexibility to outspend dwindling cash flow. Fortunately, the operators with the best financial metrics in the Bakken also tend to have high performance operations in other key oil and gas producing regions.

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