From Fake IRRs and Surplus Capital to ROCE and Capital Discipline

ROCE Deep Dive Post #2: Shale 2.0 will be significantly more profitable than Shale 1.0

In the second post of my ROCE Deep Dive series, I would like to address the legacy of poor shale oil profitability seen last decade during Shale 1.0 and what I expect to be a much brighter outlook looking forward with Shale 2.0. In a nutshell US-based oil-leveraged (“oily”) E&Ps are moving from a focus on over-stated well IRRs that drove a mis-placed growth mindset to one that recognizes the need to generate competitive full-cycle ROCE, free cash generation, and returning excess cash back to shareholders with volume objectives secondary.

Key coincident success metrics I would suggest focusing on to gain confidence incremental ROCE is on an upswing:

• <70% organic reinvestment ratio

• flat-to-low single digit per annum organic production CAGR

• Decreasing net debt, excluding net M&A

“Are you kidding, E&Ps are NEVER EVER profitable”

I can hear my former institutional investor clients saying the following:

• E&Ps have NEVER made money; you are correct that select integrated oils had a better track record back in the pre-Cambrian era (i.e., the 1990s), but E&Ps as a sector have NEVER EVER generated competitive full-cycle ROCE.

• Money remains cheap; even if capital has been slow to come back so far, you know its coming and discipline will go out the door with it; in Texas, a real man drills wells (despite some progress on diversity metrics, this tagline is still mostly accurate).

• Shale is highly capital intensive and a fast decline asset; its not like those long-lived, legacy international oil fields that drove favorable Super Major profitability in the 1990s or 2000s.

• It’s mostly the same management teams; old dogs don’t learn new tricks.

• ESG funds, climate concerns, and anti-oil actions from the Biden-Harris Administration will keep the sector out of favor.

As usual, (former client) pushback is not entirely wrong; some excellent points made. But I don’t believe it accurately describes the go forward view, which I see as considerably more favorable. I will categorize the positives into a few buckets:

1. ROCE/free cash flow/dividend focus

• More management teams are doing the math to tie well-level returns to full-cycle ROCE.

• There is a broad recognition that the failed “well IRR, drill-baby-drill” model of Shale 1.0 was an abject failure from the perspective of shareholders.

• Going forward, free cash flow and capital returns to shareholders are taking priority over growth initiatives.

2. Traditional investors, ESG funds, climate enthusiasts, and politicians all hate Oil & Gas, keeping capital markets closed and de facto capital discipline enforced

• Investors despise the E&P sector. Yes, fossil-fuel-based energy companies are broadly out-of-favor, but there is extra special derision saved for the E&P sector. It was deserved last decade, but, in my view, not prospectively — at least not for the leading larger companies.

• ESG funds, climate enthusiasts, and the current US administration are collectively creating an unfavorable backdrop for E&P capital formation—a big positive for sector profitability.

• The combination of traditional investor aversion and ESG/climate disdain toward traditional energy we can only hope keeps capital markets closed to E&P financing; it helps ensure capital discipline. I do not understand why so-called hostility toward the sector is somehow a bad thing. This is a “bizarro world” sector—what’s good is bad and what’s bad is good. Polices and preferences that de facto limit capital formation will be positive for profitability. Full stop.

3. Permian Majors matter most, SMID E&Ps do not

• In the Permian Basin, large quantities of Tier 1 acreage is now owned by the leading (mostly) large-cap players, including current and former integrated oils as well as leading shale E&Ps.

• This will lead to optimized “full field” development projects versus the previous massive drilling of random, individual wells.

• With greatly diminished investor interest, in particular post Permian Basin consolidation, SMID-cap E&Ps are no longer relevant to the go forward macro outlook. The high yield driven drilling boom of Shale 1.0 is simply not a consideration in Shale 2.0 (irrespective of whether financing markets re-open). To be clear, there is still the potential for well-run SMID E&Ps to generate competitive ROCE and share price performance; this is not a knock on the viability of all SMID E&P business models per se, where truly niche companies can carve out an interesting existence.

4. ESG/climate pressure are good for profitability

• ESG and climate pressures are ensuring more E&P companies focus on full-cycle developments including natural gas takeaway capacity (i.e., to reduce methane flaring/venting/leaks).

• There were really few things more damaging to the sector than only caring about drilling wells.

• This point bears repeating: It is my opinion that being a responsible company will be better for profitability over the long run, and, most likely, also the short-term.

Shale 1.0 retrospective: Lets relegate the failed well IRR model to the dustbin of history

There have been few strategies more damaging to the E&P sector than the “well IRR” model that characterized Shale 1.0. From a societal perspective Shale 1.0 was a massive positive as US crude oil production rose dramatically, reducing our (USA) dependence on foreign imports, improving energy security, and contributing to meaningfully lower crude oil and gasoline prices for consumers in the United States and around the world. Let us always remember that it is an absolute miracle the world can produce 100 million barrels of oil it desperately needs and wants each and every day. God Bless the oil workers of the world including the management teams that oversee the industry. Please do not mistake profitability critiques in this note with a lack of appreciation for the significant societal value created by the oil & gas industry. However, for E&P company shareholders, Shale 1.0 was an utter disaster. This note focuses on that point.

How it started — The basic E&P management promise went as follows:

• At a $50 long-term WTI oil price (or lower), our E&P company will generate somewhere between 30%-100% internal rates of return on our shale well drilling program.

• We have a 10+ year inventory of high return drilling locations.

• Since the market and Street analysts value us on net asset value and since we believe we will generate high IRRs, we are going to invest as much capital as possible drilling shale wells to accelerate value creation. By our definition, growth creates value.

• (Left unsaid: We are not going to count inevitable spending on future acreage additions, or bad wells, or risk of heterogeneity in reservoir performance, or delays/unavailability in hooking up wells to mid-stream infrastructure, or climate/other environmental costs, or taxes (deferred or otherwise), or changes to gas/oil ratios, or natural gas takeaways costs (we can always flare if nat gas goes negative!), or a bunch of other infrastructure we may or may not be spending directly on.)

• The Shale 1.0 business approach was the equivalent to my claiming the New York Yankees have been undefeated over the past decade if you don’t count all the games they lost; despite this, somehow the Yankees haven’t won a World Series title since 2009—shut-out during Shale 1.0.

How it went:

• Over 2016-2019, WTI averaged $54/bbl—similar to or better than the price on which promises were made. I am purposely excluding the 2020 COVID year as investors should excuse management teams for not forecasting a once-in-a-century pandemic. I am also excluding 2015, which was the year oil first crashed post the mid-2014 end of the Super-Spike era, resulting in massive write-downs. In other words, I am cherry-picking years that give oily E&Ps a huge benefit of the doubt.

• Sticking with 2016-2019, ROCE averaged 0.7%—yes, shale oil E&Ps were actually not-for-profit businesses despite promises of 30%-100% drilling program rates of return. ROCE for 2015-2019 was negative 4% with WTI averaging $53/bbl. The numbers for 2016-2020 were also negative 4% ROCE at $51/bbl WTI. The best individual year was 2018 with 9.4% ROCE with $65/bbl WTI.

• Let that last figure sink in. The oily E&Ps were barely cost of capital at $65/bbl WTI, despite promising investors massive profitability at $50/bbl. Seriously people, what the heck?!? When one considers what an appropriate long-term normalized WTI oil price should be, solving for the “cost of capital” return that drives sufficient supply growth is a starting point (more on this in a future post).

• Let’s be clear that blame for such poor performance is not relegated simply to management teams. Boards and equity investors were complicit. I am not a fixed income or commercial bank analyst and I sincerely don’t know how those investor groups fared so will leave them off the blame list in the absence of any actual analysis on my part.

• My apologies if the previous paragraph is preachy. I don’t know how else to write it or what other conclusion can be drawn. I do not think it is fair to solely place blame on management teams, as those of us in the analyst and investor community often do.

• Oily E&P reinvestment rates averaged 130% over 2016-2019. For those less familiar with the metric, it means companies spent all of the cash they generated plus an additional 30% that was effectively borrowed or drawn from cash or raised in equity offerings (all three happened).

The exhibit below shows ROCE for the average oily E&P as well as the best- and worst-in-class individual company over the time frame versus WTI oil prices (WTI is the bars graphed on right axis).

There has always been an IRR vs ROCE disconnect for E&Ps, but Shale 1.0 was worse

Long-time ROCE-focused energy analysts/investors will recognize there has long been a disconnect between project IRRs and ROCE. But the gap has been especially wide with shale. If I could boil it down to one factor, non-shale projects usually require a “full cycle” approach whereas the shale business was disaggregated into numerous pieces that created the illusion of better profitability for individual pieces.

Let me explain. Let’s say you are developing an oilfield offshore West Africa. With relatively limited infrastructure, an E&P company (or international major, etc.) is responsible for ensuring an oilfield will be sufficiently profitable to recover all the costs they are incurring. That would include production wells, platforms to drill and produce the wells, separation and other processing units, pipelines (or tankers) to transport the oil onshore, and possibly receiving terminals onshore. An equivalent process occurs in Canada’s oil sands where the cost to process bitumen can be quite substantial. In all these areas, an E&P company will always take into account all of the project costs, not simply the cost of drilling wells. These quick examples illustrate the absurdity on which Shale 1.0 was based. In most other countries, there is far less competition and individual project pieces are rarely outsourced en masse (though oil service and E&C companies are of course hired to perform the work).

In US shale, the business was broken into tiny pieces that allowed especially SMID-cap but also larger E&Ps to think that they did not have to consider full-cycle economics. The basic idea was drill a well and turn everything else over to someone else. In the US, we have gathering companies, long haul pipeline companies, and refineries—to name just a few—that are separately owned and operated.

SMID-cap E&Ps deserve sincere credit for the substantial risk taking and proving up of the vast oil resource potential found in our shale resource. As noted earlier, the world at large and in particular all Americans have benefited from the Shale 1.0 boom. But the outsourcing of everything has led to some really bad results, including:

• The previously unheard of creation of drilled-but-uncompleted (DUC) wells. Think about this for one minute: a company drills a well, but because the midstream company wasn’t ready to accept the oil, the well was not completed. This is in the “what the heck” category. How can you tell an investor you get 30%-100% well IRRs when you aren’t even completing the wells you drilled? (Explanations are welcome in the comments section.)

• Environmental/climate issues are unnecessarily created when, for example, sufficient natural gas takeaway capacity wasn’t built in time. While the practice of flare-to-produce oil (FTPO) is increasingly frowned upon and I believe is mostly a thing of the past, it’s difficult to fathom how this would have ever been OK. This is an example where a greater ESG focus is a very good thing for both the environment/climate and profits. At the barest of minimums, natural gas is a valuable resource (even if in over-supply short-term). I believe over 2015-2019 the world was well aware of the risks of rising CO2 and methane emissions; we aren’t talking ancient history here—just one presidential administration ago.

• The failure to recognize that just because you outsourced a cost/CAPEX, such as for gathering lines or processing facilities, doesn’t mean that the cost/CAPEX doesn’t exist. It is unclear why managements were allowed to tout well IRRs as if that was the entire ballgame.

• I’ll stop this list here or the post will never end. I think the point has been made. Mistakes were made.

The failure of the growth mindset in a mature, commodity business

In the previous section I honed in on specific issues with shale versus international projects. But that doesn’t explain the full failure. The related issue is the unwillingness of management teams and Boards in particular to call out the absurdly wide disconnect between well IRRs and corporate-level return metrics (my favorite you already know is ROCE). How? Why? What the heck?!?

Management teams were clearly convinced that drilling programs would generate 30%-100% IRRs at circa $50/bbl WTI. I believe in their sincerity on that point—i.e., I believe that they believed what they were saying. E&P managements have always been true believers based on my 30 years covering the sector.

What is baffling to me is the inability or unwillingness to see the disconnect between what was promised and how it turned out. I promise all of you that petroleum geology, engineering, and geophysics require significantly more brain power than being an equity research analyst. It’s not a close call. I am not being humble here. They are smart people and inherently have higher IQs than yours truly.

But how is it that senior management and Boards did not connect the profitability dots here. If you are promising investors 30%-100% rates of return, why would you ever need external capital? How were they not generating massive positive free cash flow, especially since oil prices were no worse on average than what plans were based on and in 2018 were a healthy $65/bbl? My guess as to the answer: lack of diversity. When everyone comes from a similar background and mindset, group-think takes over. Attend any E&P company presentation over the last decade and most sounded exactly the same.

If a management team believes it is generating 30%-100% rates of return, the logical decision is to spend as much as possible, which is basically what most of them did. What ever happened to retrospectives to tie promises to actual results?

I remember attending an Apache analyst meeting in the mid-1990s when legendary founder Raymond Plank was still involved. I believe it was his successor, Steve Farris, who gave the presentation on the acquisition look-back (overall results were good in those days). It was a really well done reconciliation of: (1) here’s what we promised; (2) here’s how it went; (3) here are the reasons for the variances. That lesson from Mr. Plank and Mr. Farris has never left me. For some reason, too many of the modern shale E&P CEOs didn’t bother with it. It couldn’t have even been done in private or presumably plans would have changed.

Resurrection: Born again after near death

Like the overweight alcoholic that narrowly escapes tragedy and vows a better future if God will just give him (definitely going to be a man) one more chance, a new day is indeed dawning. The deep double-dip, near-death downturn that was 2020 was arguably the best thing to happen to the E&P sector. The COVID era has combined with a new urgency to the ESG movement, a greater societal recognition on the need to address climate concerns, and in the United States a hostile (to the US oil industry) administration and Congress. Near death, abysmal historic returns, and an unfavorable societal backdrop are among the biggest reasons the future looks much brighter for the E&P industry.

A few points to highlight:

• Reinvestment rates are on-track to be structurally lower for the foreseeable future; I will say there is zero chance oily E&Ps will average 130% reinvestment rates any time soon. I will guesstimate that somewhere in the 70%-85% range is the max investors will tolerate. I spent time on this in ROCE Deep Dive Post #1 that you can find here.

• E&Ps have committed to various cash return strategies with a fervor they once had for production growth targets. Yes, that could change. However, the virtuous cycle of positive investor feedback and rising stock prices is going to be a learned habit that is hard to break.

• Consolidation of the Permian Basin by a number of leading, responsible, (mostly) larger companies is a huge step in the right direction. The key word here is “responsible”, which I mean in every aspect—full cycle ROCE and free cash flow generation, capital return to shareholder commitments, credible ESG and CO2/methane intensity reduction initiatives as well as traditional HSE (health, safety, environment) objectives. I suspect gender/racial diversity will be the one area industry may struggle to make more progress; that discussion is beyond the scope of this post.

• ESG commitments play an important positive role on improved profitability. If you are trying to reduce your methane intensity, as an example, you are going to take the extra steps to ensure you have sufficient natural gas takeaway capacity at all times and that the oil price and resulting cash generation are high enough to ensure you recover all your costs, not just the drilling cost.

• The holy trinity of ESG investor, climate enthusiast, and Biden-Harris disenchantment with the sector I have already mentioned. As I previously wrote here and here, I see this as more of a prospective capital starvation benefit and not a reason why the rig count ramp thus far has been slower than expected. Everyone affiliated with traditional energy should remember that all of the virtue signaling oil divestment initiatives are a net positive for industry profitability.

But isn’t shale different from legacy oil fields in a bad way?

No, I don’t think it is if you looked at if from a full field development perspective. It is true that individual wells have a natural decline rate that are much faster than what occurs in the North Sea or Gulf of Mexico or Qatar’s North Field or Canada’s oil sands. But a well decline rate is only one aspect of performance. Fiscal terms, drilling costs, infrastructure availability, lateral lengths, and numerous other factors impact overall economics.

Let me try it a different way, if you were to treat the “Permian Basin” as a project and took an optimized full field development approach as Qatar has with its super giant North Field LNG development, returns on capital in my view would be exceptionally high in the Permian. All of the issues highlighted above are at their core the problem with disaggregated, out-sourced developments. It got the shale engine going. But like a teenager driving their parent’s Porsche 911 after shot-gunning a six-pack of Meister Brau’s, the car ran off a cliff to exactly no one’s surprise (disclosure: this is not based on a true story; we never drove my high school buddy’s dad’s Porsche 911 after drinking Meisties). Optimizing well drilling with infrastructure and long-term production plateau can and will lead to competitive return on capital generation.

Likely (former client) pushback

I can hear the coming pushback to this note as I finish writing it:

Arjun, your retrospective is largely accurate, but you have not proven the go-forward outlook will be better. You are simply making assumptions and assertions that may or may not hold true and you are probably more dependent on an oil price bull market than you are willing to admit.

My rebuttal: you are correct, the future is uncertain. There is zero guarantee the E&P industry will have better ROCE going forward. But rather than add another 3,000 words to re-litigate what I just wrote, here are metrics I would focus on:

• Can a company on an organic basis (i.e., excluding acquisitions/divestitures of produce volumes) achieve 0%-3% annual production growth at a maximum reinvestment rate of 70%.

• If they can, I believe the odds favor incremental increases in ROCE and, by definition, the generation of free cash flow.

• I would also expect net debt (excluding net M&A) to decline. In a future note I will discuss the concept of future proofing for long-term energy transition; a fortress balance sheet will be a key feature of that.

• It’s not as simple as these three metrics if you are running a company. But for investors, I think modest organic production growth, <70% reinvestment rates, and decreasing net debt are excellent and easily trackable coincident indicators that portend the fate of future ROCE.

On a personal note…

In the first ROCE Deep Dive post I recognized my JPMIM colleagues circa 1995-1999 for starting me on the normalized ROCE road. The first executive to do so was Forrest Hoglund, legendary CEO of Enron Oil & Gas (now EOG Resources). This would have been in the February/March 1994 time frame (possibly 1993) as I was still at Petrie Parkman in Denver at the time. A major point of Mr. Hoglund’s remarks focused on the critical importance of generating strong full-cycle returns on capital. No E&P at the time—and frankly very few since—have stressed the importance of ROCE. That legacy has served EOG very well over my 30 year career, as one of the few truly returns-focused E&Ps. What I have always most appreciated about EOG is that when ROCE has declined, they have acknowledged it and articulated an ROCE-improvement strategy. Corporate culture matters and EOG continue to benefit from Forrest Hogland’s legacy.

(Texas Business Hall of Fame Foundation)

Disclaimer

I certify that these are my personal, strongly held views at the time of this post. My views are my own and not attributable to any affiliation, past or present. This is not an investment newsletter and there is no financial advice explicitly or implicitly provided here. My views can and will change in the future as warranted by updated analyses and developments. Some of my comments are made in jest for entertainment purposes; I sincerely mean no offense to anyone that takes issue.

Regards,

Arjun

Appendix A: Previous Post in ROCE Deep Deep Series

From Not-For-Profit to a New ROCE Super-Cycle

Appendix B: Definitions and Clarifications

Oily E&Ps include a universe of 21 US-based companies (some of which have since merged) that I track. They are mostly but not entirely shale E&Ps even as that was more of the focus here (e.g., Hess and Noble Energy). No integrated oils are included in this group. All data is from Bloomberg and S&P Capital IQ.

E&Ps - Exploration and production companies

ROCE - return on capital employed

IRR - internal rate of return