FAANG Valuations In The Shale Patch: The Fracking Darlings Are Still Expensive

by: The Beauty Contest

At current oil prices ($70 WTI), the fracking industry in aggregate is slightly above its cash flow breakeven and barely profitable.

Current valuations of fracking companies have embedded a very expensive optionality to future oil prices.

Two of the main tailwinds for the fracking industry have largely played out: the improvement in the product mix and the squeeze of the oil services names.

I would suggest investors who are willing to take oil exposure to look somewhere else: either in the oil services segment or in pure RoW upstream producers.

One year ago, we published a report where we dealt with the main independent US fracking companies and their business models. In the article, we concluded that given the poor track-record of most fracking operations, "from an investor's point of view, we think the shale revolution will prove to be a disaster", but we concluded with an optimistic note for the rest of the world saying that "from a macroeconomic point of view, we strongly disagree with those who argue that the burst of the sector will have profound consequences for the global economy. First, the losses will be mostly burdened by US investors and, second, the stability effects that the shale industry has had on the global economy so far have been far more important than any potential investors' losses. The growth in the global economy has been fragile in the last few years, and the last thing the world needs is another round of oil price increases like the ones we witnessed at the beginning of the 2000s, in 2007-08 and in 2012-2014 - the period in which the breakup of the eurozone loomed closer. The shale patch is thus one of the crucial battlefields where the war for the destiny of the global economy is taking place." One year on, I think a short update is welcome.

And what a year. The WTI price was around $50 twelve months ago but given the successful (voluntary and involuntary) OPEC cuts, a barrel delivered in Cushing is now trading around $70, for an impressive 40% revaluation in just twelve months. This has greatly helped the fate of fracking producers as reflected not only in their stock prices but in their latest financials as well, which have revealed that the fracking universe is for the first time (in a very long time) profitable - but barely so. On the other hand, given the already lofty valuations they displayed one year ago, many of these names have had a hard time in outperforming the WTI price - something that one normally takes for granted, given the operating and financial leverage of these businesses.

The other major development, of course, has been the vow of the sector in allocating shareholders' capital in a wiser fashion: you either invest in profitable projects or return the capital to investors, but the mantra of "growing at all costs" should be avoided. Although some companies have initiated a dividend policy to show their new willingness towards an improved capital allocation (and the market has applauded the decision in most cases, granting higher share prices to these companies), executive compensation (geared towards growth and little else) has barely changed so far, and the return of the investments made in the last twelve months remains to be seen. If the oil history is of any guide, the experience shows (as reported in McNally's excellent book) that the supply discipline in a market populated of small independent producers is, to say the least, flimsy.

I have updated the analysis of my fracking group as of 2Q'18 - the latest quarter for which financial results are available. The numbers go back to the first quarter of 2013. The fracking group in question is comprised of a group of 8 leading names (in order of production size): EOG (NYSE:EOG), Devon Energy (NYSE:DVN), Pioneer Natural Resources (NYSE:PXD), Continental Resources (NYSE:CLR), Concho Resources (NYSE:CXO), Cimarex (NYSE:XEC), Whiting Petroleum (NYSE:WLL), and Diamondback Energy (NASDAQ:FANG). This year I have enlarged the group including WPX Energy, so the universe is now made up of nine names (I do not rule out in the future to further expand the coverage to producers such as Oasis Petroleum (NYSE:OAS) or Parsley Energy (NYSE:PE)). The universe now covers 2.6mboepd of production, roughly 33% of the total US shale production (see here), so it gives a decent picture of the overall financial performance of the industry.

As a reminder, I did not cherry-pick the companies; instead, I chose them because they are:

  • pure frackers with no significant international activity (though Devon has been increasing its thermal assets in Canada). Some oil majors, like ConocoPhillips (NYSE:COP) or Exxon (NYSE:XOM), have significant fracking exposure, but given that their results are presented in a consolidated fashion, it is virtually impossible to disentangle fracking operations from conventional ones.
  • leading operators, either in terms of quality of their acreage or in terms of production volumes, in their respective basins.
  • Oily producers, not gassy ones,
  • and they have enough years of track record.

Spoiler alert: I maintain the conclusions reached in the original piece. One year later, the FAANG valuations so widely touted these days among the investment community not only apply to technological names but they also still apply to businesses like Diamondback Energy. In fact, among fracking names, there seems also to be the same effect going on as in the technological names: the more growth and negative free cash flow the company posts, the more absurd its valuation gets. In today's brave world of low yields, investors never seem to calm their eternal thirst for growth.

Nevertheless, I am cognizant that the expected tailwinds that the oil market will enjoy in the next months may be a temporary boost for the industry as a whole. However, the depletion of tier one acreage in many basins (as voiced by many respected wildcatters such as Mark Papa), the perennial problem of poor price realizations (something that I explore in this article in depth) and the slowing pace of technological advance are the main reasons why the sector will remain a poor cash-flow generator in the future.

In conclusion, the names tracked here remain as of the time of this writing widely expensive and produce little cash flows, so I would suggest investors who are willing to take oil exposure to look somewhere else.

The consolidated picture, as of 2Q'18

As mentioned in the introduction, the increase in the oil price has been the main catalyst for the performance of the industry over the last year. In the next graph, I have updated the cumulative free cash flows produced for the nine participants in aggregate. So far, although most of the fracking names have been able to post some cash buildup from operations over the last few quarters, the cumulative picture is still negative: only EOG and Devon have been able to produce positive cumulative free cash flows (though Devon was barely breakeven once interest payments are taken into account) over the considered time period, while most of the names have not been able to do that. Actually, for some of them, like Cimarex, Concho, WPX Energy, and especially, Diamondback the cash burned has remained recently - and the numbers do not take into account the recent acquisition of Energen by Diamondback for an incredible $9.2 billion price tag, though in all fairness in an all-stock transaction:

Cumulative free cash flow and cash interest payments, selected fracking companies, 1Q'13-2Q'18

Source: Company filings and own elaboration. Cons. stands for consolidated numbers.

For the interested readers, I have left below some more aggregated summary statistics. Summing up, these names have an aggregated net debt of $27bn. (substantially down from the $38bn. reached in 2015), have produced free cash flows (before interest payments) over the last twelve months of $3.8bn, production has grown in one year from 2.2mboepd to 2.6mboepd and has raised equity capital in net terms (taking dividends into consideration) over the last five years of $15.2bn. With these numbers, it is surprising, to say the least, how the sector as a whole can still command such high valuations. In other words, it is clear that in these prices is embedded a very expensive optionality for future increases in oil prices.

Main operating and financial indicators, consolidated fracking companies, 1Q'13-2Q'18

Source: Company filings and own elaboration.

Price realizations are still too low - and that will not change

We argued last year that probably the biggest reason for the lack of historical performance of the fracking industry was the price realizations usually commanded in the patch field. With this, I do not mean the recent takeaway problems in places like the Permian basin widely touted by the press, problems that, as always in the commodity universe, will take care of themselves in due time. The problem around price realizations is a more fundamental and irreversible one, geological in nature: shale production is simply not too oily, which given the current price gap between oil and NGLs and natural gas, matters a lot.

The fact that financial commentators do not get this point yet does not mean that the management teams of the fracking companies have committed the same sin. In the following graph, I have tracked the evolution of the "product basket" (oil, NGLs and natural gas) for our nine fracking companies over the last 5 years. You can see that as gas prices have been pummeled and have not recovered from the previous highs while the oil price has, the fracking companies have been pushing for more oil in their product mix drilling more oily areas. And the improvement has been impressive indeed: from a share of less than 40% in 2013 to slightly more of 50% as of today. However, most of the improvement was achieved in the first couple of years, suggesting little upside from current levels. In other words, the geology and frackers ingenuity may have already reached their limits here.

Evolution of the product mix in our fracking universe, 1Q'13-2Q'18

Source: Company filings and own elaboration. Continental and Concho do not breakdown NGLs production, so I have (optimistically) assumed that all the NGLs production is oil production.

The difference in the product mix directly translates to the overall price realization for a barrel of oil equivalent (BOE). Though several fracking companies tout the high realizations achieved in their barrels of oil versus the WTI, the number that matters to investors is the price realized for the BOE. But as you can see in the following graph, the frackers BOE is not as good as it seems. The historical price realizations have commanded an average discount of 35-40% versus the WTI over the last five years. Given that the numbers only run up to the 2Q'18, the graph does not fully capture the recent widening of the spreads for the Permian names. Price realizations markedly improved because of hedges when the oil market crashed in 2015, but conversely, the hedges have been a drag over the last few quarters.

Evolution of the WTI, frackers' realized price and discount vs. WTI, 1Q'13-2Q'18

Source: Company filings, Bloomberg and own elaboration. The BOE realized for the group has been obtained as a weighted average of the group's total production.

In any case, beyond hedges and temporary transportation gluts, the takeaway is clear: frackers' discounts will remain wide and around 35%, absent a spike in gas prices. Therefore, if the WTI is trading around $70, you may be sure that your fracker is getting on average between $42 and $45 for their BOE. As you can see, even before considering the cost structure, the bar for the fracking companies is already set very high.

In summary, one of the reasons for the improved performance of the fracking companies over the last five years has not only been technological improvements but the strategic shift from a gassy basket to an oily one. But given the recent trends displayed in the graphs, one cannot but conclude that this tailwind provided by Mother Nature has already largely played out.

The Canadian oil sands - a template for the effect of technological change?

But what about the rest of the technological improvements usually touted by the fracking companies and media alike? Just to name a few:

  • The ability to drill longer lateral wells: from 5,000 ft. some years ago up to more than 13,000 ft. currently.
  • The ability to introduce more frack sand stages (the number of times the rock is fracked over the same length) per lateral well: from 20-25 to 30 stages.
  • More volume of sand per well: from 2,000-3,000 tons per well to more than 5,000 tons currently.

As we argued last year, most of these advances are real (for instance, the increasing cost derived from pumping more sand to the well is more than offset by the resulting increase in oil and gas production), and I am confident that continuous "tinkering" and human ingenuity will still have some runaway ahead to push down costs. However, it is difficult to gauge to what extent these improvements are technological in nature or not - e.g. they might have come from squeezing oil service companies or from the product mix shift discussed above.

So I have decided to take a look at another chapter in the history of the oil industry as a guide. Specifically, I have zeroed in on the evolution of another niche of the oil market that also claims that they are in the business of "manufacturing": the Canadian oil sands. After years of very poor performance in terms of return to capital and the surge of the fracking industry with its short-cycle projects (versus the slow pace of development of a Canadian greenfield project), the oil sands industry has fallen from grace - especially among US investors. Many investors will object that the comparison is not accurate enough, given that: i) the nature of the Canadian assets is very different, they are very big projects in nature with long leads to fully ramp-up, ii) unlike their US cousins, oil sand companies face perennial problems in terms of infrastructure, iii) in Canada, mineral rights do not belong to the landowner, as in the US and iv) the environmentalist opposition is even stiffer in Canada than in the US, delaying projects, infrastructure and the pace of oil sands technological development. However, even acknowledging these differences, their position as a traditional marginal producer (as many US basins are today) and the hopes put in cost reductions brought by technological progress more than a decade ago make the Canadian oil sands a suitable comparison to the US fracking industry.

In a landmark study published by the Oxford Institute for Energy Studies (OIES) a couple of years ago, they tracked the evolution of costs of a typical Canadian greenfield oil sand project over the decade 2003-2014. For a mining project, they saw the costs rising from $14boe (before blending and transport costs) to $64, (for an astonishing compounding growth rate of 16.5%!), whereas for SAGD projects costs rose from $14 to $53, for a CAGR of 14%. The graph does not seem to depict the evolution of a manufacturing activity as the Canadian producers claim, where stepped learning curves are usually gleaned, but rather the evolution of a business that is subject to the Ricardian extensive margin - i.e. better lands are exploited first (in modern terminology, "high-grading"):

Greenfield oil sands project supply cost build-up, in real ('14 dollar) terms, 2003 vs. 2014

Source: Oxford Institute for Energy Studies (2016), The Future of the Canadian Oil Sands, p.36.

These costs increases occurred in a period where technological improvements were clearly achieved. For instance, as they show later in the report, the production per well for in-situ methods rose from 350-400 bpd to 500bpd. Actually, if one considers SAGD methods as oil sands 2.0 version, the technology of the Canadian oil sands clearly leaped forward over the traditional mining methods (steam-oil ratios for SAGD improved over that period). Finally, gas prices, a critical input for in-situ methods, though not a "technological improvement" per se, trended down on average, providing additional cost tailwinds to the oil sands.

If one considers the Canadian oil sands to be one of the marginal producers of the world, the result is not surprising at all; after all, a marginal producer should not be able to obtain a meaningful return on its capital, so the oil sands costs have risen pari passu with the oil price - exactly as elementary economic theory would predict. So what did happen? In a nutshell, as the report says, "[s]ubsurface uncertainty and the need to show attractive economics lead to the common oilfield practice of high-grading, producing the most attractive portions of the reservoir first."

Fortunately, the OIES wrote a shorter follow-up report last year, which documents the developments occurred in the oil sands industry after the price crash of 2015-2016. And after a decade of continuous increases in costs, it seems the industry has been able to reign in costs, reducing breakeven costs between $15 and $25, depending on the estimate and the extraction technology used:

Estimates of Breakeven Costs including 12-15% return, various sources, 2015 vs. 2017

Source: Oxford Institute for Energy Studies (2017), A Restrained Optimism in Canada's Oil Sands, p.17.

This deflation path is eerily similar to the one showed by the fracking names, and to a large extent, it is probably due to the deflation cycle in the services segment of the industry. Because if you look at the evolution of costs for other marginal producers, like the ones involved in deepwater projects, the result is the same, with breakeven costs down between 15% and 25%:

Estimates of Breakeven Costs including 12-15% return, various sources, 2015 vs. 2017

Source: Goldman Sachs (2018), Oil Top Projects 2018, p.4.

In other words, everything seems to indicate that the "increase in efficiencies" reported by the fracking companies (and Canadian names) is a more recent general phenomenon, and probably the outcome of a long decade where costs were out of control in the oil industry, rather than anything related to technological change. Although this cost normalization after years of excesses may prove to be partially sustainable, this source of additional cost reductions is basically over, and from now on will see whether the technological improvements are enough or not for the fracking industry to offset the depletion of tier one prospects.


Some bullet points as a way of summary:

  • At current oil prices ($70 WTI), the fracking industry in aggregate is slightly above its cash flow breakeven and barely profitable (let alone obtaining a decent return on capital of, say, 10-15%). In any case, current valuations have embedded a very expensive optionality to future oil prices.
  • Two of the main tailwinds for the fracking industry have largely played out: the improvement in the basket mix will likely be constrained by geological considerations going forward and the service sector squeeze, which has occurred in other niches of the oil industry as well, is over.
  • If history is of any guide, the technological improvements of other extraction techniques that are repeatable and manufacturing-like, like the Canadian oil sands (especially the SAGD variety), are important, but unable in the long-run to fully compensate the increasing costs derived from using more marginal projects.
  • I would suggest investors who are willing to take oil exposure to look somewhere else: either in the oil services segment or in pure upstream producers in the rest of the world.

Disclosure: I/we have no positions in any stocks mentioned, and no plans to initiate any positions within the next 72 hours.

I wrote this article myself, and it expresses my own opinions. I am not receiving compensation for it (other than from Seeking Alpha). I have no business relationship with any company whose stock is mentioned in this article.

Additional disclosure: Acknowledgment: Thanks to Sebastian Fender for helpful comments on an earlier draft of this article.