(2)The Shale Bubble: An Investment Opportunity of a Century

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Summarizing the main points from part 1

  1. The world outside of U.S. & Canada doesn’t produce more crude than it did back in 2005.
  2. The oil glut was created and is completely dependent on unconventional oil from the U.S.
  3. The U.S. Shale boom didn’t start because of new technological breaks true, but was made possible by aggressive monetary policy. The first horizontal oil well was drilled in 1929.
  4. The production of unconventional wells falls rapidly in the first three years and then enters a sustained period of low production.
  5. The average well experiences a YoY decline of 40% and is down around 80-90% after 3 years
  6. As a result, Shale fields require significant drilling activity and thus significant ongoing capital investment to increase, much less maintain, production levels.
  7. Moreover, the cost of an unconventional well could be as high as five times the cost of a conventional well.
  8. Wells in the Permian and Bakken fields cost, on average, $5.5 million and $8 million, respectively. In contrast, a conventional vertical well can cost from $1 million to $3 million.

With this information in mind, we can draw the conclusion that lower oil prices will result in no profitability for the Shale operators. No profitability should lead to lower capital expenditures, and production should drop exponentially because of the Red Queen Syndrome (new and high-producing wells have to be drilled constantly to maintain steady production across unconventional fields).

This, however, leaves us with two important questions unanswered?

  • If the Shale players are so uneconimical, why are people claiming that they are showing great resilience?
  • Why is not production falling faster and are the producers about to ramp up production with recovering prices?

A Tale of Capex

For the conventionals, the amount of crude oil produced declines at between 2% and 5% per year. Since the output falls so gradually, wells typically keep pumping for 20 years or longer. The wells’ long lives help account for the extreme volatility in oil prices. Naturally, producers plan their projects expecting to recoup the upfront investment required to find the oil and install the well––their “fixed costs”––and the “variable” or “marginal” costs of extracting the oil year after year, notably labor and electricity.

In a business where the risks stand as tall as the rigs, companies only invest when they forecast future prices far above the total outlay of fixed and variable costs, in hopes of pocketing big profits. The rub is that energy prices frequently fall far below what’s required to return their full costs, let alone make a decent return. When prices drop, however, almost all conventional wells keep pumping. That’s because the variable cost of lifting the crude is still far lower than the prices it fetches on the world market. Ten-year old wells often have variable costs of just $20 to $30 a barrel, so their owners keep on producing at prices of $60 or $80, even though it would require $100 oil to generate a good return on their total investment. In other words, what they spent to drill the well becomes irrelevant. All that matters is the cash they can generate over and above what’s required to suck out the crude every day.

The end result is that production lags the aggregated amount of capex invested. Even if capex is high for an extended period, it will take some time for the projects to have any noticeable change to production.

Unlike conventional projects, capex has immediate effect on production for the Shale producers. The high initial production mixed with the low exploration cost means that Shale players recoup a significant amount of their initial investment in the first years. When capex is high, like it has been for the last years, production increases rapidly. But as producers need to constantly drill new wells, an absence of capex will work in the opposite direction. In fact, fracking is a lot more like mining than conventional oil production. Mining companies need to dig new holes, year after year, to extract reserves of copper or iron ore. In fracking, there is intense pressure to keep replacing the production you lost last year. Below is a video demonstrating a timelaps of the drilling & fracking of a Shale well.

The key take away is as long as the Shale operators have access to capex, their production will be resilient. Capex has artifically been kept high in Bakken & Eagle Ford for the last year. Even if cash flows from operations has been depressed following the price crash in oil, the Shale operators have been given an abundance of capital, letting them continue to run capex far over DD&A.

DD&A stand for Depreciation, Depletion and Amortization, where depletion should be the decline rate of each well multiplied by the cost (decline rate * (cost of the land + the cost too drill & complete)). Its first in this year capex has fallen below DD&A for the Shale operators. For Capex to be below DD&A is worrisome as it, in theory, means that depletion is increasing faster than the additional capex is contributing with.

How are these operators doing financially?

Lucky for us, there are tons of available empirical data to examine, as the majority of the Shale operators trade on the stock market. The best way to understand the Shale operators true core profitability, and simultaneously avoid problems like earnings management, is to look at cash flow metrics like cash flow from operations (CFO) and free cash flow (FCF).

EOG Resources, Inc. (EOG)

Let’s start and look at EOG, the A-student of the Shale operators (the best of the bad). EOG, also called the “father fracker”, leads the drilling in the Eagle Ford.

*The table displays EOG’s cash flow profile in a re-written template format. The table is displayed in million of dollars. Operating Cash Margin (OCM) is another word for adjusted CFO. Most of the headings in the template should be self-explanatory. “Net capital expenditure” doesn’t include disposal of businesses,  M&A etc, as this amount is displayed in “Other non-operating income/(expenditure)”. The (Increase)/decrease in cash is shown in the opposite sign in order for the template to balance.

  • OCM is down 67% between FY14-16.
  • For FY16, OCM is 81 % of DD&A (USD 3,553 M).
  • Current Capex is below DD&A.
  • At current oil prices (~$50/bbl), I forecast EOG to produce around USD 4,280 M in OCM for FY17, which will be above DD&A (USD 3,553 M).


EOG Resources has said that it will increase capital expenditure (excluding acquisitions) with ~25%. That will fuel 5% increase in total production to 587,900 boe per day (guidance 608.7mboe-567.1mboe per day).


EOG is one of the few Shale companies that can actually ramp up production while still retaining a somewhat “sustainable” cash flow profile. The production guidance for 2017 is still far below its peak.

Notice the difference in the two diagrams. The diagram above shows EOG’s entire crude production, while the diagram below shows EOG’s crude production in the U.S based on drilling activity. In the last month, the large majority of the increase in production has come from the Permian basis, which have been milked since the 1920s with a peak in production in the early 70s. The large increase in U.S. oil production in the last year has come from Bakken and Eagle Ford, not the Permian. Most of the companies have been forced to leave the Bakken and Eagle Frod to focus on Permian alone, which is in itself evidence that these Shale plays aren’t economical viable at lower prices.

ConocoPhillips (COP)

  • OCM is down 74% between FY14-16.
  • For FY16, OCM is 63 % of DD&A (USD 9,062 M).
  • Current Capex is below DD&A.
  • At current oil prices (~$50/bbl), I forecast COP to produce around USD 8,481 M in OCM for FY17, which will be below DD&A (USD 9,062 M).
  • I see no scenario where COP is ramping up production aggressively in the near term future.


COP said its production in the first quarter of 2017 would be between 1,540 million-1,580 million barrels of oil equivalent per day. As I expect OCM to be lower than DD&A for FY17, I expect production to continue to trail down. Notice COP’s high capex level (USD 15,482) in FY14 which contributed with the impressive growth in production in the following year. Future capex will not come close to these levels any time soon. That COP is single handily dependent on Eagle Ford and Bakken for their U.S. production doesn’t make the situation better.


Marathon oil (MRO)

  • OCM is down 79% between FY14-16.
  • For FY16, OCM is 65 % of DD&A (USD 2,395 M).
  • Current Capex is below DD&A.
  • At current oil prices (~$50/bbl), I forecast MRO to produce around USD 2,331 M in OCM for FY17, which is below DD&A (2,395M)
  • I see no scenario where MRO is ramping up production aggressively in the near time future.


For 2017, MRO expects full-year production in the range of 375–405 Mboepd, a midpoint fall of ~4 Mboepd (or ~1%) from its 2016 production of 394 Mboepd. Notice that the production in the Eagle Ford are now falling with the same level as it was previously growing. I see no reversal here and expect production to continue to trail down.

Here is a quote from 2014 capturing the overoptimistic animal spirit (wrt the Eagle ford) at the hight of the bull market. I bet the management feels different about these investments today.

As of year-end 2014, Marathon Oil held approximately 180,000 net acres in the Eagle Ford play in South Texas, where we have been operating since 2011. The Company’s acreage is located primarily within Atascosa, DeWitt, Frio, Gonzales and Karnes counties, with operated producing wells in the Eagle Ford, Austin Chalk and Pearsall formations. Marathon Oil has invested strategically to grow its presence in the formation’s highest value oil and condensate core areas, consistent with its focus on developing unconventional, liquids-rich resource plays. Marathon will be drilling in South Texas for many years to come and the Eagle Ford is now a core to the company’s production growth plans.

Anadarko Petroleum Corporation (APC)

*The Toronox settlement (USD 1.2 B) is adjusted out of OCM for 2015 and is the reason why the template doesn’t balance in this year.

  • OCM is down 72% between FY14-16.
  • For FY16, OCM is 62 % of DD&A (~USD 4,301M)
  • Current Capex is below DD&A.
  • At current oil prices (~$50/bbl), I forecast APC to produce around USD 4,216 M in OCM for FY17, which is below DD&A (4,301M).
  • I see no scenario where APC is ramping up production aggressively in the near term future.


APC’s production guidance range provided for fiscal 2016 is 716–721 Mboepd. We can see a similar pattern for APC, in that Eagle Ford are dropping in production in similar pace to which it was growing with before.

Whiting Petroleum (WLL)

  • OCM is down 62% between FY14-16.
  • For FY16, OCM is 66 % of DD&A (USD 1,171 M).
  • Current Capex is below DD&A.
  • At current oil prices (~$50/bbl), I forecast WLL to produce around USD 898 M in OCM for FY17, which will be below DD&A (USD 1,171 M).


WLL expects its 2017 production to increase 23% between 1Q17 and 4Q17. Full-year production guidance for 2017 is 45–46 MMboe (million barrels of oil equivalent). This increase in production seems abit odd to me, but might be valid as OCM has been more robust compared to the other players. The reason for the higher performance in OCM is because of WLL’s hedging program. As of January 1, 2016, WLL had derivative contracts covering the sale of approximately 54% of our forecasted 2016 oil production.

Continental Resources (CLR)

  • OCM is down 58% between FY14-16.
  • For FY16, OCM is 93 % of DD&A (USD 1,710 M).
  • Current Capex is below DD&A.
  • At current oil prices (~$50/bbl), I forecast CLR to produce around USD 1,900 M in OCM for FY17, which will only be USD 200 M above DD&A

CLR has managed to keep their production constant, but the impressive growth in 2014-2015 has died down. Notice that CLR’s capex level for FY15 was 2x DD&A, which still was not enough to keep the production growth.


Devon Energy Corporation (DVN)

  • OCM is down 77% between FY14-16.
  • For 2016 OCM is 72 % of DD&A (~USD 3129M for 2015). DD&A for 2016 seems underreported.
  • Current Capex is below DD&A.
  • In 2015 the company divested USD 1934 M to cover its shortage in cash.
  • At current oil prices (~$50/bbl),  I forecast DVN to produce around USD 3,766 M in OCM for FY17, which will be slightly above DD&A (3,129).

Chesapeake Energy Corporation (CHK)

Q4 not reported yet

Hess Corporation (HES)

Q4 not reported yet

Pioneer Natural Resources Company (PXD)

  • OCM is down 69% between FY14-16.
  • For 2016, OCM is 61 % of DD&A (USD 1,480 M).
  • At current oil prices (~$50/bbl),  I forecast PXD to produce around USD 1,364 M in OCM for FY17, which will be below DD&A (USD 1,480 M).

Concho Resources Inc. (CXO)

  • OCM is down 46% between FY14-16 (using a large amount of hedging)
  • For 2016 OCM is 90 % of DD&A (USD 1,167 M).
  • Current Capex is above DD&A, but CXO has required an USD 1,135 M issue in equity to finance this.
  • At current oil prices (~$50/bbl)  I forecast PXD to produce around USD 1,468 M in OCM, which is above DD&A (USD 1,167 M).


  • What’s deciding total production from the Shale players are access to capital markets. If the capex level is keept elevated by loose lending practises, production will be robust.
  • What matters for the long term investor, is that this behaviour is not sustainable in the long run. Cheep money and QE won’t be around forever, Shale will be punished when they lose access to capital markets and unlimited credit.
  • Going long the best of conventional and offshore drilling (which is sustainable) will provide a huge payoff in the future.
  •  This case will with most certain require a very long term investment horizon. I want to emphasis that the investor will be required to invest throughout the market cycle.

Continue to part 3

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