As we all take a break to celebrate America’s political Independence, it’s worth contemplating how Energy Independence has become attainably within sight over only the past couple of years. In 2015 oil production and energy sector prices were falling as many worried OPEC would bankrupt large swathes of domestic production. In October 2016 the pain of lower prices became too much (see OPEC Blinks). They abandoned their strategy of low prices in favor of production cuts, and altered the future of the U.S. energy sector.

It reminds of past titanic struggles; the 1940 Battle of Britain, when the German Luftwaffe gave up trying to destroy the RAF’s airfields because of persistent aircraft losses. Or even the end of the Cold War when America’s economic might supported military spending beyond the capability of the Soviet Union to keep up, leading to its collapse. Capitalism, technological excellence, relentless productivity improvements and a drive to win are all American strengths that were tested by OPEC and found more than up to the challenge. There may not have been a ticker tape parade down Broadway to mark the victory, but it will turn out to be as consequential for America as some past military exploits. We have much to celebrate, and add the Shale Revolution to that list.

MLPs performed unusually well last week. Our volume of nervous incoming calls peaked with the incidence of bearish crude oil comments in the media. The chart below shows sentiment visually reaching an extreme. No amount of typing by this blogger can shake the solid relationship between crude oil and energy infrastructure. It may be a volume driven, gas-focused industry, but holders of AMLP often think like oil traders which becomes self-fulfilling. Consequently, an over-abundance of bearish stories predictably caused a recovery. MLPs didn’t dissociate from crude, they rebounded with it.

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We naturally watch crude movements closely since some client discussions involve tactical thinking, but there were other sources of research and news that were more interesting last week.

John Mauldin’s widely read blog Outside the Box featured an interesting piece on the geopolitical consequence of American energy independence (see Shale Oil: Another Layer of US Power). It includes some startling estimates, such as that the U.S. now has the world’s largest recoverable oil reserves (Rystad Energy), or that 60 percent of all crude reserves that are economically viable at $60 per barrel or less are located in U.S. shale reserves (Wood Mackenzie). Acknowledging the substantial improvements in productivity, the blog notes, “A shale oil driller in the United States, moreover, doesn’t need to be more profitable than Saudi Arabia to drill new wells; the driller just needs to fetch a sufficient return on invested capital. When prices are low, drillers simply forgo exploration and concentrate on the completed wells that produce enough oil to justify their existence.” This last point refers to “short-cycle” projects, which are the essence of shale production. Capital invested is returned within several quarters with output hedged. There’s less focus on Exploration and more on Production.

Saudi Arabia and Russia both require oil prices at least $25 per barrel higher to balance their budgets. It’s unclear how this Math will resolve itself, but it’s likely to highlight America’s strengthening energy position, through higher prices or the benefits of energy security.

Goldman Sachs also produced some thoughtful research. They expect shale production to continue increasing over the next decade before peaking in the late 2020s. They note the benefits of mergers between Exploration and Production (E&P) companies with adjacent fields as such combinations allow for longer laterals that straddle previous separately owned acreage. EQT’s recent acquisition of Rice Energy is an example. There is increasing use of Machine Learning and Artificial Intelligence to optimize drilling techniques. Many private companies unheard of outside the energy industry provide vital services relying on new technology. Biota, a biotechnology start-up founded in 2013, applies DNA sequencing to microbes in the earth’s subsurface. The analysis helps identify sweet spots for drilling. Welldog supplies a fiber optic down-hole monitoring system. Spitfire provides software tools for faster data analysis. EOG has been collecting real time data on every rig and well they control so as to make it available to decision makers in the field. Public policy is solidly behind Energy Independence. On Thursday, the President said, “The golden era of American energy is now underway.”

These are some of the reasons that in Shale, America is the only game in town.

Enjoy Independence Day weekend.

It’ll be no surprise to MLP investors that the correlation of our asset class with crude oil has been rising. Falling crude in 2015 led MLPs to drop 58.2% from high to low, a figure we won’t soon forget. That same institutional memory among investors is imposing a similar relationship today. Last time, lower oil led to lower U.S. production, posing challenges for midstream infrastructure businesses with surplus capacity. This time, higher U.S. production is leading to lower crude prices. In This Time Is Different, Reinhart and Rogoff take readers through the many financial disasters that befell investors who thought it was different. And yet, with due deference to the aforementioned luminaries, we think it is.

Last week we received more questions than usual from investors reviewing the mark-to-market damage inflicted by their MLP allocations. One investor noted that MLPs were responsible for fully all of the YTD losses in one model portfolio they run. If you’re wondering whether the relentless sellers possess an insight you’re missing, you have plenty of company. Higher production of hydrocarbons in the U.S. is bad for lots of players including OPEC, but it’s hard to fathom why it’s bad for the domestic infrastructure that supports the Shale Revolution. American shale oil output is on track to grow by 1 Million Barrels a Day (MMB/D) annually. Shale output of 5.4 MMB/D is now more than half of total U.S. oil production of 9.3 MMB/D, in a global oil market that’s producing 98 MMB/D.  Furthermore, the fact that U.S. shale producers are growing production at ever lower costs is more likely bad for the other 95% of global producers.

The market is failing to differentiate U.S midstream energy companies that benefit from this growth in market share from the rest of the global energy losers.  At the annual MLPA Conference in Orlando a few weeks ago, MLP managements were similarly puzzled by the weakness in their stock prices. But they were far less worried than most investors, because they generally don’t need to tap the capital markets much to finance their growth plans.

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It’s hard to find research that is bearish on MLPs, which is not especially comforting from a contrarian standpoint. The most negative case is probably the view that crude is going to $30 and will take MLPs lower with it. Before ascribing some additional insight to sellers, remember that over $40BN of retail money accesses the asset class inefficiently via taxable, C-corp funds such as AMLP (see Some MLP Investors Get Taxed Twice). Our investors, self-selected as they are, are an intelligent bunch. But they (you) are not representative of an investor base that includes those who accept a 35% corporate tax drag on their returns. Investment insight is going to be rare among this subset, and based on published fund flows they are responsible for some portion of the recent selling.

For those who enjoy analyzing statistical qualities of returns, the chart below compares the correlation of MLPs with crude oil and subsequent performance. It turns out that following periods of high MLP/crude correlation, MLPs do rather well. The 30 day correlation is 0.61, so the 90 day correlation used in the chart below is most assuredly heading higher over the next few weeks. A high 90 day correlation is typically followed by a good 90 day return. The correlation of this relationship is 0.63. It’s been said that if you torture the data enough it’ll tell you whatever you like, and some may believe that’s what’s going on here.

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On the other hand, MLPs and crude oil shouldn’t move together nearly as much as they do, so when they dance too closely perhaps nervous sellers create an opportunity. In researching the components of the Alerian MLP Index, we calculate that only 25% of the cashflows are derived from crude oil. Some large MLPs have very little crude exposure, including Enterprise Products (EPD) at 17% and Williams Partners (WPZ) with 5%. Others such as Oneok Partners (OKS) and EQT Midstream (EQMP) have 0%. And this is the percentage of their cashflows derived from volumes of crude passing through their systems, which are only loosely affected by the price of crude. Natural Gas Liquids (mostly Ethane, Propane, Butane, Iso-butane and Pentane) are most commonly separated from the natural gas (Methane) with which they’re extracted. NGL prices tend to move with crude oil, but together these still represent less than half the cashflows of the Alerian index. As with crude, volumes are the principal driver of NGL-related cashflows, with their prices being of secondary importance. Nonetheless, MLP prices move with crude oil, reinforcing the understandable fixation MLP investors have with oil even though it’s hard to justify based on underlying fundamentals. In our fund we have an overweight to crude oil-oriented infrastructure businesses, but we estimate this at around 32%, so 7% higher than the index.

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On another topic, last week we fielded a few questions from holders of Rice Midstream Partners (RMP). EQT recently acquired RMP’s General Partner (GP) Rice Energy (RICE). RMP slumped, because it highlighted a theme of our investing, which is that you don’t need to own an MLP to control it; owning the GP is sufficient. RMP investors have few rights, and the supply of accretive dropdowns they were expecting from their GP will now be redirected to EQM, a loss of future value over which RMP investors have little recourse. It’s why we invest in GPs (see MLPs and Hedge Funds Are More Alike Than You Think).

We are invested in EPD, EQGP (GP of EQM), Oneok (OKE, GP of OKS) and Williams Companies (WMB, GP of WPZ).

It usually pays to invest with management. In the hedge fund industry that has rarely been possible. Although most hedge fund managers invest in the fund they run, their wealth has come from owning the hedge fund General Partner (GP), which manages the fund. Opportunities to invest in hedge fund GPs are rare; they don’t need your capital and have little desire to share the lucrative economics.

In 2012 I wrote The Hedge Fund Mirage; The Illusion of Big Money and Why It’s Too Good To Be True. The book pointed out what most hedge fund managers know – that hedge funds have been a great business and a lousy investment. Fees have eaten up virtually all the investment profits. Money still flows to hedge funds, because there are and always will be some good ones. But the farther you stray from a unique, specialized strategy the more prosaic your returns. The book drew some nice reviews and provoked few critics, because most industry insiders preferred to minimize awareness of the lopsided split of investment returns. Being controversial turned out to be great fun, and caused us to think differently about another asset class.

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Master Limited Partnerships (MLPs) look like hedge funds. Although they own actual infrastructure assets rather than stocks, bonds and currencies, they share their organization as partnerships with hedge funds and private equity. MLP investors, like Private Equity (PE) fund investors, have limited rights. They’re called “Limiteds”, because Limited Partners (LPs) have little recourse once they’re invested (see The Limited Rights of Some MLP Investors).

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Not all MLPs have a GP, but many do and given how well hedge fund managers have done it’s no surprise that the people who run MLPs prefer to invest in the GP. The issue doesn’t receive much attention, but research we’ve done shows that in a select group of MLPs (i.e. those we care about) management has 25X as much money invested in GPs versus LPs.

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Hedge funds and PE funds classically pay their GP “2 & 20”. This 2% management fee and 20% of the profits means, for example, that an 8% return after fees required a 12% return before fees. The 4% difference goes to the manager. MLPs pay their GPs Incentive Distribution Rights (IDRs), which direct a portion of the MLP’s Distributable Cash Flow (DCF) to the GP. The DCF split typically starts low but goes up to 50%, so the GP’s share can tend towards half.

The power of this becomes clear when you consider the financing of a new pipeline. GPs direct their MLPs to do something, the same way a PE manager directs his PE fund. A new pipeline is designed, planned, built and operated by an MLP on instructions from its GP, who then receives his share of the additional DCF created. Asset growth for PE managers is invariably beneficial, and it’s generally true as well for MLP GPs.

The best time to own hedge fund, PE or MLP GPs is during periods of asset growth. The Shale Revolution (see America Is Great!), with its growing output of crude oil, natural gas liquids and natural gas, is driving the need for more infrastructure assets. Recognition of this is behind the 25X statistic noted above.

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It’s not a perfect analogy. For example, hedge fund investors have in aggregate done rather poorly, whereas 10 year MLP returns of 7.2% are better than REITs, Utilities and Bonds. Since MLP’s generally only raise equity from taxable U.S. investors tolerant of a K-1, they are limited to this relatively small portion of the global equity market. Those MLPs whose growth plans required several $BN have given up the lucrative GP/MLP structure in favor of being conventional corporations. But, as the 25X table shows, a decent number find the MLP structure still works.

At the MLPA Conference in Orlando a few weeks ago, questions usually concerned near term fluctuations in demand for one asset or another. We think the big trade here is America’s Path to Energy Independence, and owning GPs that benefit from continued infrastructure development. Conference chatter as well as attractive valuations show that it’s not yet a crowded trade.

We’re not the first MLP investors to be puzzled by sector weakness in the face of growing oil and gas production. This was visible most clearly on Wednesday, when a sharp drop in crude following inventory numbers caused similar drops in many MLPs. Crude prices are weak precisely because of the success of technology in lowering costs, most obviously in the Permian in West Texas where most of the growth in output is occurring. Higher than expected U.S. production is mitigating the impact of OPEC’s production cuts. This ought to be bad for producers of conventional crude oil elsewhere in the world, and good for the owners of U.S. energy infrastructure handling greater volumes. So far, that hasn’t been the case.

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Moreover, Permian-exposed Exploration and Production (E&P) companies are faring better than the MLPs that service them. This year MLPs with Permian exposure have lagged the Alerian Index. With rising output depressing prices, one might conclude that investors regard any increased utilization of infrastructure assets as temporary. Low crude will eventually feed through to reduced production and commensurately less need for pipeline and storage capacity. At odds with this view, the U.S. Energy Information Administration recently raised its 4Q18 forecast of output to 10.2 Million Barrels a Day (MMB/D), up from their 9.4MMB/D forecast of only four months earlier.

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MLP investors may not believe this will happen. And yet, within the  E&P sector, those E&P companies with significant exposure to the Permian are outperforming the E&P index. Pioneer Resources (PXD) is outperforming all three MLPs we’ve highlighted, while Plains GP Holdings (PAGP) is underperforming all but one of the E&P names.

It seems that MLP investors and E&P investors are drawing sharply different conclusions from the same set of data on oil production. Or more precisely, potential MLP investors are declining to commit capital because they assess the outlook differently from E&P investors. At some point these views will have to reconcile, which we expect will result in higher MLP prices.

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There’s a similar divergence with bonds. Since the low in the energy sector on February 11^th last year, the High Yield E&P sector and MLPs have roughly kept pace with one another. Over the last few months they have diverged, with MLPs underperforming. Since E&P companies are generally MLP customers, it’s odd for the prospects of the customers to be improving without a positive knock-on effect for MLPs. But for now, that is what’s happening. The same data on output is supporting different conclusions by various investor types.

Last week was the annual MLPA conference, in Orlando, Florida. It’s safe to say the guests at nearby Walt Disney World had a more carefree time than beleaguered MLP investors. One long-time attendee described the mood as “glum”, noting that energy sector investors had expected a more vigorous rebound.

Although the conference is organized around presentations by management teams in the Hyatt Regency’s cavernous ballrooms, the private meetings that take place on the periphery are far more valuable. It’s also nice to catch up with some familiar faces.

We had a full schedule of meetings with management teams, usually with just one or two other investors in attendance. The most pressing question for MLP investors of late is, if Exploration and Production (E&P)  companies (i.e. MLP customers) are continuing to increase production of oil and gas, why isn’t this good for MLP stock prices?

In fact the entire energy complex has had a terrible few months. MLPs are -2% YTD although the sector feels as if it’s been falling for months. Meanwhile, the Oil Services ETF (OIH) is -22%. U.S. crude output is 9.2 MMB/D (Million Barrels per Day) and is widely expected to reach 10 MMB/D next year by many observers, including OPEC. 1Q earnings for E&P names as well as for MLPs recently were generally good with positive guidance. The fundamentals remain encouraging . To paraphrase a typical question from a financial advisor invested in our mutual fund, “If you’re so smart, how come we’re losing money lately?”

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When asked about recent stock price weakness, MLP executives were similarly puzzled. The good news is that they’re not spending much time worrying about it – following the 2015 Crash many steps were taken to reduce reliance on the fickle equity markets. Leverage is down and distribution coverage is up. Distributions have been held flat and in some cases cut in order to finance growth, while growth projects have been screened for higher returns. Generally, MLPs don’t have a pressing need for capital. While stock price weakness makes both management and investors poorer, it’s not being met by a desperate rush for capital to complete projects. And in some cases, such as Targa Resources (TRGP), equity capital even at lower prices was nonetheless attractive financing for their recently announced Natural Gas Liquids pipeline from the Permian Basin to North Texas.

In short, management teams usually exuded excitement about greater utilization of their existing infrastructure and growth plans. They dismissed the high recent correlation between MLPs and crude oil as a temporary phenomenon and not reflective of improving midstream fundamentals. For investors who rely on the market to confirm the wisdom of their recent decisions, it’s a time for patience while America’s journey to energy independence sends ever more hydrocarbons through our pipelines, processing units and storage facilities.

We enjoyed the discussion with Tallgrass Energy (TEP) CFO Gary Brauchle. We’ve followed TEP for a while (see Tallgrass Energy is the Right Kind of MLP). Four years ago their Rockies Express natural gas pipeline (REX) looked increasingly redundant as its west-east flow from the Rocky Mountains to Ohio faced growing competition from the Marcellus shale. TEP reversed the flow on the eastern end of this pipeline, and is looking at making the entire line two-way. Apparently our meeting was the same day as a bearish report from an obscure research analyst, but his criticisms must have lacked substance since nobody raised the subject.

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The MLP investor base has changed in recent years. Pre-Shale, it was an income generating asset class with modest growth. The Shale Revolution created a substantially greater need for capital to fund growth, such that during 2010-13 MLPs were raising more in equity than they were paying out in distributions (see The 2015 MLP Crash; Why and What’s Next). The conversion of the investor base from income seeking to growth seeking was not smooth. One CEO estimated 75% turnover in his shareholders over two years.

Topics of discussion included the drop in attendance from last year, although the convention facility is so big it rarely seems crowded. There was some surprise at the pricing of Antero Midstream GP’s (AMGP) recent IPO, with a yield of 1%. Even with the 73% annual distribution growth forecast by one underwriter, by 2020 it would still yield just over 5%. They may pull it off, but sharing some of that execution risk with an eager set of IPO investors seems like a smart move.

Those who had seen the presentation from the IPO roadshow chuckled at the inclusion of SnapChat as a comparable (because of its very high cashflow growth). We thought that, along with the pricing, betrayed a fairly demeaning view of investors by management. It seems most things need to go right for AMGP, and a stumble will expose the gulf in valuation between AMGP and, say, Plains All American (PAGP) with its 10% Distributable Cash Flow (DCF) yield. If MLPs were in a bubble, AMGP would be Exhibit 1, except they’re not.

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In chatting about Energy Transfer, several investors remembered last year’s self-dealing transaction in which Energy Transfer Equity (ETE) issued preferential securities just to the management team (see Is Energy Transfer Quietly Fleecing its Investors?). It’s still possible a Delaware court could rule against ETE and order the transaction be cancelled.

In many of the meetings managements were peppered with very granular questions about percentage utilization of a particular asset next quarter. These generally came from sell-side analysts looking to refine their models so as to forecast the next quarter’s earnings and DCF. No doubt these are important topics, but we feel such “forest for the trees” questions miss the big picture. America is heading to Energy Independence, and midstream infrastructure is vital to that goal. In the near term, it might seem important to try and forecast a quarterly fluctuation, but it’s very hard to do so consistently.

Far more importantly, over the next few years what other asset class can possibly compete when America is headed towards being the world’s biggest crude oil producer (see America Is Great!)? Last November OPEC lost, and consequently our E&P companies are gaining market share. The short-cycle projects that are Shale represent a completely different risk paradigm to conventional drilling with its inherent uncertainty over returns (see Why Shale Upends Conventional Thinking). Gathering and Processing networks with their close exposure to the wellhead are more exposed to volume uncertainty in the short term, but over the longer term they’ll be utilized. These are the issues that will drive returns, and while most investors are probably aware of the big picture their questions often betrayed a blinkered view.

MLP management teams hold substantially more money in GPs compared with MLPs when given the choice within the GP/MLP structure. What could be a more powerful statement about the upside they see than their personal investment in the vehicles with operating leverage? The managements of Energy Transfer Equity (ETE) and TEP are communicating their opinions with their commitments of personal capital (see table at the end of The Limited Rights of Some MLP Investors).

In discussing their allocation to MLPs, I often ask investors what is the next most attractive sector of the equity markets beyond energy infrastructure, with its huge tailwinds, substantial future growth and 7% yields selling at 30% off its 2014 all-time highs. It doesn’t require much thought to buy what’s rising, but not much else is cheap.

In summary, value-seeking investors should draw comfort from the complete absence of irrational exuberance at this year’s MLPA conference. Today’s MLP investors are for the most part a patient bunch.

We are invested in ETE PAGP, TEGP (the GP of TEP) and TRGP

Last Wednesday Plains All American (PAGP) held their Investor Day. These events typically afford investors the opportunity to get more detail on the company, but Plains also has a sophisticated macro view of the oil market. As the biggest crude oil transportation company in America they naturally care a lot about North American output. CEO Greg Armstrong invariably provides many great insights. Below are some selected slides from their presentation.

Plains’ research focuses more on forecasting volumes rather than prices; as befits an energy infrastructure operator, the volumes of crude oil moved are more important than the value, although there’s clearly a linkage because high prices stimulate output.

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The first slide notes the sharp drop in upstream capex budgets which will eventually manifest itself through constrained supply. The 2015-16 drop in budgets is the biggest in thirty years. There is little excess output capacity, and notwithstanding recent weakness in oil prices, over time the market will be increasingly vulnerable to a spike.

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The second slide notes the impact of OPEC’s production cuts. Plains held their Investor Day a day before the OPEC meeting which extended the cuts through 1Q18. Note that the right hand chart assumes the 1.2 Million Barrel/Day (MMB/D) OPEC cut is extended, which should approximately absorb global inventories in excess of historic averages. Russia and other non-OPEC producers are expected to make up the balance of the 1.8MMB/D contained in their announcement. In short, Plains believes the market will balance as a result.

This slide on U.S. inventories notes their currently high level compared with prior years but also that recent builds have been substantially lower than in the past.

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During the Q&A session, CEO Armstrong referred to shale drilling as a manufacturing process, a common analogy nowadays because the short cycle nature of shale projects (see Oil Futures Say Shale’s Here to Stay) results in fast return of capital with commensurately less risk. Much of this higher capital velocity is driven by improving efficiencies (see Extracting Supply Forecasts from Oil Futures).

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One example of efficiencies is the use of multi-well pads. This can sharply increase the production from each rig in use, but comes with logistical challenges. Typically, all the wells are drilled first, then fracked. This lengthens the time from initiation until production and increases the upfront capital investment; it also results in more variable output as the bottom right illustration in the above slide shows, with volumes coming in spurts. The uneven output creates additional challenges for the Exploration and Production (E&P) company as well as the supporting infrastructure.

Today there is far greater certainty about the returns from a given level of investment than has traditionally been the case for the energy industry. In fact, Armstrong noted that forecasting production relies heavily on knowing how much capital E&P companies will commit (which is itself dependent on expected returns). The reasonably high visibility around output given capex informs the table below, showing several decades of resource availability. In a memorable quote, Greg Armstromg said, “The world may not need another million barrels a day of Permian crude, but it’s coming.”

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Lastly, investors often ask whether there is excess infrastructure. The answer is never simply yes or no. New pipelines are typically built in anticipation of growing supply. Production ramps up steadily, whereas a pipeline offers capacity only when it’s completed.

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The result is, when you plot pipeline capacity and supply of product, you get a chart like this one. The market seeks a narrow gap between the red line (pipeline takeaway capacity plus refinery demand) and the grey area (production). But capacity comes online in a step function, while production moves more gradually. Too much capacity can hurt pipeline margins, but insufficient capacity can leave E&P companies scrambling for alternative transportation (rail or truck, both much more expensive). The challenge for companies like Plains is to build charts like this correctly and then plan their infrastructure investments accordingly. It’s why they focus so carefully on the fundamentals driving their E&P customers.

On a lighter note, I can report that hydraulic fracturing (“fracking”), the process by which water is injected at high pressure into the porous rock holding hydrocarbons, thereby creating millions of cracks and releasing it, has found its way into popular culture. Brockmire, a show available on Amazon Prime, centers on a baseball announcer covering a minor league team in Pennsylvania (think Marcellus Shale) called the Frackers. A local E&P company sets its sights on the (poorly attended) Frackers stadium for waste water disposal. I won’t spoil the plot any further, but discussion of fracking and shale are no longer limited to members of the energy sector. Our thanks to MLP investor Michael Hickey of Forest Park, IL for drawing this to our attention.

We are invested in PAGP

With the resurgence in U.S. crude oil production over the last year, it was only a matter of time until shale output reached a new record. Based on recent actual production and the EIA’s forecast for a June increase of 122 MB/D (thousand barrels a day), the peak of March 2015 is only 57 MB/D away.

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The Permian Basin in West Texas has been the principal driver of this increase in production. The depth of the play, as illustrated in the slide from a recent presentation by EOG (displayed above), holds substantial reserves and has benefited from extraordinary improvements in efficiency by the operators there which has brought down break-even levels. Many have underestimated the ability of the U.S. private sector to harness technology as effectively as they have. This is activity that OPEC expected to choke off through a ruinously low price of oil. Instead, they were forced to switch gears last November and concede steadily increasing market share to U.S. producers. Recently, OPEC quietly raised their 2018 forecast of total U.S. oil production (shale and conventional) to 10 MMB/D (million barrels a day). Given the capital being invested by drillers it’s plausible that by 2018 the U.S. could be the world’s biggest crude oil producer.

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The most visible recent pipeline protest was against Energy Transfer’s (ET) Dakota Access Pipeline (DAPL) earlier this year. One of President Trump’s first actions was to correctly overturn an Obama-era executive order blocking its completion. But public demonstrations against fossil fuels continue elsewhere, even if their mentally agile adherents comfortably drive to join their friends in shouting against oil and natural gas.

As a consequence, managements of energy companies are recognizing that they need a strategy to deal with such protests, since a delayed pipeline can quickly become costly. At their Investor Day earlier this month, Williams Companies (WMB) CEO Alan Armstrong discussed their evolving attitude towards groups that seek to frustrate the implementation of infrastructure projects. Striving to learn from ET’s experience with DAPL, Armstrong described a policy of actively engaging with opponents to find common ground. He also noted the potential of other groups, such as construction unions keen for the jobs, to line with WMB in pushing projects forward.

Expect to see more savvy use of media by energy companies, including video of American workers making America Great accompanied by fast-paced, inspiring music. The WMB Analyst Day included a couple of short clips. Here’s another on WMB’s blog page (called “Pipe Up”), extolling the benefits of their Northeast Supply Enhancement project.

The education of investors about tax-inefficient MLP funds received a welcome boost from Barron’s. A letter from Mike Flaherty noted the tax drag on many poorly structured MLP funds included in a recent article, “Best ETFs for Income“. Flaherty correctly pointed out the value-destroying corporate tax liability incurred by AMLP and AMZA amongst others. Asked to respond, one PM blandly referred investors to seek tax advice, which is what you’d say if you ran a poorly designed fund and wished to change the subject. Barron’s hasn’t yet assigned a journalist to write on this topic, in spite of our suggestion that they’d be performing a useful service to countless MLP fund investors. But perhaps they will soon.

We are invested in Energy Transfer Equity (ETE) and WMB

We thought it would be interesting to expand a little more on the notion that crude oil prices reflect the market’s confidence that oil in the future will be available on approximately the same terms as today (see Oil Futures Say Shale’s Here to Stay). The tool we’re using is the two year spread – the difference between the spot price of crude and the futures price two years hence. The chart below plots spot Brent crude and this two year differential. We used Brent because it’s more reflective of the global oil price. Until late 2015 U.S. crude oil exports were limited to Canada, so the U.S. benchmark WTI reflects some price distortions caused by the export ban. However, it broadly conveys the same information as Brent.

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From 2010-2014, with crude oil above $100, the two year spread was negative (known as in backwardation). Crude futures two years out were trading at $5-$15 less than spot. This was the time of the great ramp up in U.S. shale output, and although export constraints kept it in the U.S. by reducing U.S. imports the global market felt its effects.

In 2014, Plains All American published a great chart which showed that North American output had been equivalent to fully all of the new global demand for crude oil over the prior four years. As we all know, OPEC responded to this concurrent loss of market share by allowing prices to collapse later that year.

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As spot crude dropped, the two year spread moved sharply positive (known as contango). There are many factors driving the slope of the crude curve, not least of which is storage for near term contracts. High levels of inventories will tend to depress spot prices versus future ones, so the spread offers a guide with these caveats. With that said, two years ago the market was signaling that supply would only be available at sharply higher prices. The market was reflecting an expectation that OPEC’s strategy of bankrupting large swathes of the U.S. shale industry would be successful. Had it happened, the drop in supply would have allowed crude to return to substantially higher prices and vindicated OPEC’s strategy.

OPEC conceded defeat in November and agreed to cut production. This allowed prices to rise and in recent months has brought the two year spread back towards $0. Today’s oil prices reflect confidence that future supply will be available on roughly the same terms as today. Since capex commitments into conventional oil plays keep falling (see Why Shale Upends Conventional Thinking) and shale is bucking the trend with increased drilling budgets by the Exploration and Production (E&P) companies active there, a logical inference is that oil traders expect continued increases in shale output.

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The success of shale drilling is due in no small part to continued technological innovation. E&P companies such EOG and Pioneer include examples of the impact of IT on their activities. American technological innovation is increasingly what’s driving the Shale Revolution. Below are six slides from earnings presentations to illustrate:

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Fracking 3.0 focuses on more targeted areas supported by detailed geological analysis to identify the best spots to drill. It also uses more grades of sand including very fine grains, resulting in greater variety of cracks being propped open as the water/sand mixture ruptures the rock.

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Often the drill bore used to drill the well is remotely guided by an operator sitting in a control room miles away. Increasing data mining allows for greater precision in drilling the most productive spots.

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Artificial Intelligence and Predictive Analytics play a role. Often, today’s oil drillers leave their hard hat at the door to sit in front of a computer screen.

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This slide from EOG illustrates the extraordinarily deep layer of exploitable rock formation in the Delaware (Permian) Basin in West Texas, compared with much shallower opportunities in the Eagle Ford (South Texas) and Bakken (North Dakota). They compare the thickness of the Delaware Basin play with the distance from Battery Park in lower Manhattan to City Hall. The Permian makes possible multi-layer drilling which greatly improves the economics.  It’s why there is so much interest in the Permian.

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This illustrates how EOG has been able to raise the percentage of its wells defined as “Premium Standard” based on meeting a certain minimum  After Tax Rate of Return (ATROR). On their earnings call last week EOG had Sandeep Bhakhri, Chief Information and Technology Officer. Bhakri provided a summary of EOG’s intense use of data to make accurate, fast decisions. EOG is a leader in providing actionable data to front-line personnel which allows them to adapt drilling plans as they receive new information. As he said, “We built 10 web-based self-service applications, eliminating the need for employees to ask each other what questions and to instead focus on why and how questions.”

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Finally, this slide is EOG’s analysis of the required break-even for various sources of crude supply globally. U.S. shale is the swing producer because its opportunities are short-cycle, able to return capital invested within a matter of quarters. But shale is no longer the marginal producer. Based on this chart, the price of crude oil will eventually need to move higher in order to draw enough supply to meet demand.

E&P companies are the customers of MLPs, so their success is obviously important. Recent earnings reports from E&P companies, as well as the energy infrastructure businesses that are vital in getting their hydrocarbons to market, support growing output. This is confirmed by the U.S. Energy Information Administration, which recently increased its forecast of U.S. crude output to an average of 9.3 MMB/D for 2017 and nearly 10.0 MMB/D in 2018.

This greater certainty about future supply is reflected in the narrowing dispersion of price forecasts for crude oil (see U.S. Oil Output Continues to Grow). Steadily growing hydrocarbon output is expected by the energy industry and the U.S. Federal government. Even OPEC expects more U.S. oil production; last week they increased their forecast U.S. growth by 285K barrels a day, to 820K. It’s a factor causing OPEC to likely extend last year’s production cuts, which further concedes market share to shale.  The only place where growing U.S. output is seemingly not expected is in the stock prices of MLPs, as investors know only too well. The last chart, from midstream business Enterprise Products (EPD), shows that it’s not only U.S. E&P companies expecting the market to balance at current/planned levels of supply.

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The strong correlation between crude and MLPs from 2015 is well remembered by many and is part of the history of every risk model, which probably reinforces today’s connection. But the continued operating efficiencies of U.S. shale drillers are supporting higher levels of production at lower prices than many investors expected. A key difference between 2015 and today is the two year oil spread, which reflects a far more positive view of sustaining domestic production than was the case during the MLP Crash. MLP investors shaken by the recent drop in the sector would do well to consider the information reflected in other markets.

We are invested in EPD

A couple of months ago (see Why Shale Upends Conventional Thinking) I promised to spread constructive thoughts about Master Limited Partnerships (MLPs) across the ensuing weeks and months rather than use them all up on the first drop in prices. Two months and several percent later such parsimony was well advised. If your preference is to invest with a stop-loss, thus ceding to others the timing of your exit and avoiding the need to think too hard, MLPs may not be your best choice.

Lower oil prices may lead to lower U.S. output (although it hasn’t happened yet) and consequential pressure on the owners of infrastructure as excess pipeline and storage capacity build. If the 2015 MLP collapse was an epic, 2017 is so far a single episode in a mini-series of unknown length.

The bear case is plain enough. U.S. oil production remains stubbornly high (at least from OPEC’s perspective). Since crude oil is now below the price that prevailed when OPEC shifted strategies, U.S. shale output is more than offsetting last year’s agreed production cuts. The agreement is being surprisingly well respected with few reports of cheating. However, while OPEC members are complying with production cuts their exports remain at previously high levels, drawing down inventories. ClipperData’s Matt Smith pointed this out last week, adding that April was the first month when Saudi Arabia cut exports in what may presage a more meaningful reduction in global supply.

A certain amount of self-confidence is necessary to buy securities that others are selling — how else does one buy, anyway? But just because one is bullish does not render the naysayers stupid. If crude oil falls far enough production in the U.S. and elsewhere will slow. Shale drillers are not immune to prices, and in fact are better able to respond than most due to the short-cycle nature of their projects (see What Matters More, Price or Volumes?). The secular improvements in horizontal drilling and hydraulic fracturing are relentlessly lowering break-even prices for the Exploration and Production (E&P) companies that are active there. These E&P firms are the customers of MLPs, so we care very much about their success.

There is a type of circular irony here, in that continued growth in U.S. output aided by productivity improvements is causing energy sector stocks to weaken. The very success of shale in America ought to be a problem for others, not for domestic E&P companies or the MLPs serving them. For now, production and price are negatively correlated – shale supply stubbornly refuses to surrender to lower prices. Or more realistically, efficiency improvements maintain production higher than it might otherwise be but nonetheless lower than would be the case at, say, $60 a barrel.

Production may slow and the worriers be proven right. So let’s complicate matters by considering a number of facts shared in the many earnings reports over recent days.

EQT Corporation (EQT) reported lower than expected natural gas output because, as CEO Steven Schlotterbeck explained, “A couple of our frac contractors decided to pay us the penalties to take their frac crews to jobs that were more profitable.” In other words, demand in the Permian in West Texas is sufficiently strong to induce frac suppliers to break contracts in the Marcellus, in Pennsylvania.  Think about this, you have a profitable shale well that you wish to drill and have contracted a crew to drill it and instead they pay you a penalty not to drill the well because economics are that much better elsewhere.

There are many indications of new capital being invested in shale drilling. Western Gas (WES) reported that their sponsor Anadarko (APC) had sold Eagleford and Marcellus assets in 1Q17. WES owns infrastructure supporting these plays, and as a result CEO Benjamin Fink said, “we therefore expect increased drilling activity behind each system.”

Similarly, ENLK’s Barry Davis noted of their sponsor, Devon Energy (DVN), “Devon recently announced the potential divestiture of certain properties in Johnson County, an area that was not competing well for ongoing capital investments in their portfolio, from an EnLink perspective, we could benefit from a transition of those assets from Devon to a producer who is committed to developing the area over the long term.”

APC and DVN are not short of investment opportunities, but are concentrating their capex budgets on their best ones. They’re evidently finding interested buyers in assets whose sale proceeds will finance even more profitable opportunities. The new money will work those assets harder than the previous owners, which WES and ENLK see as good for them. In commenting on the Permian, ENLK’s Barry Davis further noted, “In the core areas where we are positioned, oil weighted breakeven prices or (sic) around $30s per barrel making economics very attractive, at today’s prices the resulting rates of return are in the range of 80% to 100%.”

Early last year, during what turned out to be the late stages of the MLP MOAB (Mother Of All Bears), we looked at Crestwood (CEQP) and their bankrupt E&P customer Quicksilver Resources (see How Do You Break a Pipeline Contract?). Owning a pipeline that supports a play whose owner can’t pay his debts is not what MLP investors like, and some wondered if CEQP would wind up owning infrastructure that was under-used or repriced.

Quicksilver’s assets were sold in bankruptcy court to Bluestone Natural Resources. Fifteen months later, CEQP’s CEO Robert Phillips commented, “And finally, in the Barnett, Bluestone our new producer has been running a very active work over program, consistent with what we are seeing from other producers in the Barnett as well these very inexpensive work over programs are high return, expenses for the producers. And we are continuing to see volumes over and above our estimates work over program led to a 4% volume increase over the fourth quarter and the first quarter.”

As we saw before, financial distress for an E&P company need not lead to production cuts, but can instead result in a more efficient owners maintaining or even growing output.

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The oil futures curve provides an interesting perspective. Falling MLP prices suggest lower crude prices will ultimately cut shale output and reduce the use of existing and planned infrastructure. But in fact deferred futures contracts have fallen farther, which only makes sense if the market expects shale output in 4-5 years time to continue being an important source of supply. If the prospects for the shale industry were dire, oil traders would bid more for longer term contracts expecting to profit from ultimately less U.S. production. But in fact they’re doing the opposite, suggesting oil traders wouldn’t short the U.S. shale industry.

Predicting the short term moves in MLPs will inevitably require being an oil trader. Your weekly blogger cannot change that. But studying the earnings reports,  transcripts and futures market over the last couple of weeks does offer a more granular perspective on the many positive developments taking place in U.S. shale.

We are invested in CEQP, ENLC (GP of ENLK) and WGP (GP of WES)

We’re in earnings season again, and last week we listened to US Silica’s (SLCA) conference call on Wednesday morning. Weakness in MLP prices due to softer crude oil is incongruous with the positive outlook communicated by SLCA’s CEO Bryan Shinn. Volumes and pricing were both up 15% quarter-on-quarter, with sand volumes in their Oil and Gas segment up 79% versus a year ago.

The continued innovation in shale drilling extends to varying the grades of sand used and generally quantities too. Moreover, while some analysts are concerned about overcapacity in the sand industry, CEO Shinn noted that because different grades of sand are not easily substituted, total supply capacity needs to be 20-25% greater than demand in order for the market to clear. He noted projections of 100 million tons (MT) of demand in 2018 (up from 75 MT this year), versus optimistic 2018 supply estimates of only 90 MT.

To SLCA, higher prices will be needed for the market to balance. U.S. shale drillers, who are the customers of MLPs and consumers of sand, show every sign of continuing to increase production. Breakevens continue to fall, with costs coming down another $10 per barrel across many shale plays over the past year. Shell’s CEO recently noted that break-evens in the Permian Basin in West Texas were $40 per barrel. This will support ongoing demand for the infrastructure and support MLPs provide.

The shale industry is producing more, while MLP investors remain nervous about the price of crude oil (see MLP Investors Not Yet Convinced).

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Meanwhile, the International Energy Agency noted that global oil discoveries and new projects fell to historic lows last year with 2017 expected to offer little improvement. For three straight years exploration spending has been half of what it was in 2014. They contrasted the sharply reduced investment spending in the conventional oil sector with resilience of the U.S. shale industry.

Oil has been very volatile over the past three years, swinging from a high of $106 per barrel in June 2014 to $26 in February 2016. Historically, both supply and demand have been fairly inelastic which has resulted in fairly modest shifts in producer/consumer behavior translating into large price moves. The supply response function has historically been slow; if the world suddenly needs another 1 million barrels a day, there isn’t a dormant oil field that can be suddenly switched on. From discovery to production with a conventional field is years. Similarly, if supply is just a little more than the world needs (as was the case in 2015) it takes quite a price drop to induce a supply reduction.

Conventional oil (and gas) projects are long cycle. By contrast, U.S. shale is short cycle in that wells can be drilled inexpensively and begin producing within months, with the high initial production rates allowing faster payback of capital invested. The availability of short cycle oil projects should make the supply response function shorter, which in turn should reduce the volatility of oil. This is why Exxon Mobil and other major energy firms are redirecting their capital spending (see Why Shale Upends Conventional Thinking).

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Our thanks go to good friend and client Gerry Gaudet for directing us to the chart above. It compares the dispersion of oil forecasts in recent years, and the range is the narrowest in a decade. In other words, market participants are converging on a narrower likely price range for oil price as they incorporate the growing role of short cycle, U.S. shale into their supply models. This greater certainty is also likely to flatten the price curve for oil and perhaps even cause it to invert to backwardation (i.e. future prices lower than current), at least until something happens to upset these forecasts. One inference (apart from unexciting times for oil traders) is that projects with a breakeven much above $80 a barrel are going to be hard to finance since so few forecasters expect that high a price.

We are invested in SLCA