U.S. Oil Output Approaches Record

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.

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.

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

Extracting Supply Forecasts from Oil Futures

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.

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.

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.

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:

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.

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.

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.

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.

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.”

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.

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

Oil Futures Say Shale's Here to Stay

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.

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)


U.S. Oil Output Continues to Grow

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).

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).

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


MLPs and Tax Reform

We’ve had a number of questions over the past 24 hours about the impact of the White House tax proposal on Master Limited Partnerships. Therefore, we’re posting our thoughts now rather than in our normal Sunday morning missive.

There’s not a great deal of specifics so far, but we’ve put together a table illustrating how it might impact after-tax returns for MLP investors and also how it might affect equity investors in corporations. Because MLPs are pass-through entities with no corporate tax liability, the tax reform proposal implies that the new, low corporate tax rate would apply to investors in MLPs rather than personal tax rates on investment income.

The proposed tax changes are good for most businesses. The biggest losers are likely to be taxpayers living in high-tax states such as NY, NJ or CA who currently receive significant deductions for state and local taxes (including property taxes) paid. We’ll leave that analysis to others.

For corporations, the lower corporate tax rate leaves more after-tax income to be paid to equity investors. We’ve assumed that tax rates on personal income and investment income are unchanged so as to focus in on the impact of the corporate tax rate change. We’ve also limited this analysis to Federal taxes. MLP investors often benefit greatly from deferring taxes on most of their distributions, which lowers their effective tax rate. We’ve ignored this deferral benefit as well for the analysis, although many investors (your blogger included) have MLP holdings that date back many years. But we’ve also assumed that corporations distribute all their after-tax income whereas in most cases they reinvest a portion back in their businesses and buy back stock which also defers taxes for the long term holder. Tax analysis inevitably requires making lots of assumptions.

With all these caveats, the boost to after tax income for all investors is significant, although it’s larger for MLP investors. It’s also worth noting that the relative attractiveness of MLPs compared with corporations increases with tax reform. In our example, MLP investors currently retain $60.40 from their investment versus $49.53 in a corporate structure, or 22% more. This advantage increases to 31% ($85 versus $64.77) following tax reform.

There are secondary effects too – if tax reform boosts GDP, corporate profits should rise as should energy consumption, which will drive increased demand for energy infrastructure.  Furthermore, while not specifically addressed in the proposal the administration has signaled its openness to accelerated write-offs benefiting capital intensive industries with large growth capex opportunities, such as the energy infrastructure sector.  They’ll also want to avoid creating economic uncertainty, so we shouldn’t expect contractionary moves, such as the ending of deductions for business-interest payments.

We think tax reform could provide a significant boost to MLPs by increasing the after-tax return to investors.

This blog discusses tax issues specific to MLPs. However, this is not intended to be specific personal tax advice. Each investor’s tax situation is unique and for specific advise you should seek the counsel of your own tax adviser.




MLP Investors Not Yet Convinced

Investors in Master Limited Partnerships (MLPs) have long become accustomed to daily fluctuations in crude oil affecting sentiment for the sector. The slide describing midstream infrastructure as a toll model with limited commodity sensitivity has been dropped from client presentations. It’s no longer credible. The Shale Revolution has shifted the industry from one of stable cashflows with modest growth to one where identifying growth opportunities is the most important element of security selection. It’s why this is the most attractive sector in the equity market.

The feedback loop between oil prices and MLPs persists – for short-term traders, lower crude suggests lower U.S. output and vice versa. Daily moves in commodity prices cause investors to recalibrate their MLP appetite, respecting the past pattern that oil and MLPs are irretrievably linked.

Oddly though, U.S. oil production seems fairly insensitive to prices. As the above chart shows, volumes have been increasing steadily even though the oil price has been going nowhere. It remains stubbornly below OPEC’s $60 objective following their strategy shift in November. During the collapse in 2015 MLP investors feared declining volumes would hurt cashflows, although the preponderance of long term shipper commitments meant that operating results were only modestly affected. Today, all the signs are that volumes will continue increasing. MLP investors are not yet convinced.

As we noted last month (see Why Shale Upends Conventional Thinking), short-cycle projects are commanding an increasing share of capex budgets of the biggest oil companies because they’re less risky. Shale projects generate output with far less up-front investment, allowing greater synchronization of capital deployed with revenue earned. This should also result in lower oil price volatility. The long lead-time of conventional projects means the supply response function is very slow. A spike in oil prices can’t easily induce immediately greater conventional supply. Short-cycle projects are much more responsive to price. U.S. shale drillers were able to curb unprofitable production quite quickly even while dramatic improvements in productivity allowed output to remain far more robust than OPEC expected. Unfortunately for oil traders, it’s likely to be a far less exciting market than in the past, because the U.S. is increasingly a nimble supplier easily able to adjust supply as conditions warrant.

Earlier last week Plains All American (PAGP) announced open season on a pipeline system from the Permian in West Texas to Cushing, OK. Recent quarterly earnings reports showed that most MLPs have plans to increase capacity in anticipation of greater volumes. In West Texas Leads a New Oil Boom we noted the entry of Exxon Mobil (XOM) into shale. They’re far better able to maintain their investment spending through a cycle than the independent drillers that came before them, which will in turn reduce volatility in output.

While the U.S. is increasing output, supply is shrinking elsewhere. The International Energy Agency forecasts a growing global supply shortfall, the result of the sharp capex reduction that’s taken place since 2014 (see America Is Great!). For the same reason, the head of Saudi Aramco warned of a looming oil shortage. Goldman Sachs (see chart below) noted that global oil inventories are the lowest in three years. It doesn’t look as if we’ll be short in the U.S., but globally there are plenty of reasons to expect gradually tightening supply.

Consistent with this, U.S. exports have also been increasing since Congress lifted the export ban in late 2015. Prior to that, U.S. oil could only go to Canada, and while they’re still our biggest buyer, the next three in 2016 were the Netherlands, Curacao and China.

Investing in businesses positioned to benefit from the growing need to transport oil (PAGP), store it (NuStar GP Holdings, NSH) and provide sand for fracking (US Silica, SLCA) hasn’t been especially rewarding this year. But the signs increasingly point to growing demand for the assets and services provided by companies such as these.

We are invested in NSH, PAGP and SLCA

NuStar Acts Like a Hedge Fund

Last Tuesday, in a kind of return to normalcy, NuStar Energy (NS) funded an acquisition the way Master Limited Partnerships (MLPs) normally do; by issuing equity.

NS is an MLP controlled by a publicly traded General Partner (GP) called NuStar GP Holdings (NSH). As we’ve noted in the past, an MLP with a GP looks very like a hedge fund with a hedge fund manager. In this version of the analogy, NS is the hedge fund and NSH the hedge fund manager (i.e. hedge fund GP).

So to clarify what NS has done – they’ve invited in some new Limited Partners (think hedge fund investors) via their secondary offering of 12.5 million LP units raising $579MM (before fees). This money will, along with additional debt proceeds and cash, be invested in their $1.475MM purchase of Navigator Energy Services, owner of gathering and processing assets in the Permian Basin in West Texas. This looks just like a hedge fund leveraging new client capital to invest in assets, except that NS is buying physical assets rather than stocks, bonds or currencies like a hedge fund.

Like a hedge fund manager the GP, NSH, has directed all this activity while only providing their minor 2% GP share of the equity capital. NSH receives Incentive Distribution Rights (IDRs) from NS which are a function of NS’s Distributable Cash Flow (DCF). Since NS owns more assets, they’ll throw off more DCF which can only be good for NSH. So like any competent hedge fund manager, NSH will receive a portion of the cashflows generated by assets that it controls but does not finance.

We’ve written about this in the past (see Energy Transfer’s Kelcy Warren Thinks Like a Hedge Fund Manager)

NSH CEO William E. Greehey understands this profitable asymmetry better than most, because he personally owns 21% of NSH. He also regularly buys additional NSH units on the open market. The Hedge Fund Mirage; The Illusion of Big Money and How It’s Too Good To Be True (Wiley 2012) revealed that 98% of the profits generated by hedge funds had gone in fees to managers. Being a hedge fund client is often financially punitive and rarely anything like as lucrative as being a hedge fund manager. Although MLPs have easily outperformed hedge funds, it’s often still the case that GPs do better.

Greehey’s $250MM personal investment in NSH is augmented with $150MM in NS, so he is in a way invested alongside other NS holders. However, since the IDRs paid by his NS units are returning to him via his NSH ownership, he’s enjoying substantially better terms than the others. It’s like investing in a hedge fund for no fees, which given that industry’s history is usually the only sensible way to do so.

Of course, there’s always the risk that NS might have agreed to pay too much to acquire Navigator Energy Services, in the same way a hedge fund might invest its clients’ capital in a low-returning asset. The risk of overpaying is largely borne by NS (i.e. the hedge fund clients) since it’ll reduce the returns they’d otherwise earn. The impact on NSH is more muted – after all, they didn’t provide the capital in the first place so their downside is a bit less cashflow received on virtually nothing invested. NSH has agreed to waive its IDR payments on the new money for the first ten quarters, which helps the numbers in the short term but will still nonetheless provide accretive cashflows for the GP indefinitely thereafter.

Since investors are generally advised to place their capital alongside management, which in this case is clearly in NSH, one might ask what is driving the selection of investors who instead choose NS? But we won’t ask the question too loudly, because it is the existence of willing NS investors that creates value in NSH. After all, what use is a hedge fund manager with no hedge fund? Similarly, an MLP GP without a ready market for units in the MLP he controls is worthless. So NS holders will gamely look past the 7% drop in stock price on the day the secondary was announced and draw solace from the exciting prospects described by management on their explanatory conference call (although failing to allow questions made the exercise fairly pointless).

Hedge fund clients often warmly regard new investors as confirming their earlier insight, and pay little heed to the possibilty of a dilutive return on the additional capital raised. The more astute GPs chant “We Love Our LPs”, which is the mantra of every GP in finance. As holders of NSH, we love NS investors. Not so much that we’d want to be them of course, but they can feel the love and that’s what counts.

We are invested in NSH

The Global Trade in Natural Gas

One of the many benefits of the Shale revolution has been a reversal of the U.S. terms of trade with respect to natural gas (see U.S. Natural Gas Exports Taking Off). We’ve long been a net importer and the Sabine Pass LNG (Liquified Natural Gas) facility in Louisiana was originally intended to augment pipeline inflows with waterborne imports. The discovery of so much commercially viable and cheap domestic natural gas upended these plans and several years and billions of dollars later Sabine became the first of several LNG export facilities.

Owner Cheniere Energy (LNG) just announced their 100th LNG shipment. One of the most stunning developments in this arena has been LNG shipments of natural gas from the U.S. to the United Arab Emirates (see Coals to Newcastle). You have to be pretty good at producing it cheaply in order to cover shipping costs to a region of the world awash in hydrocarbons. And in America, we are.

Natural gas pricing has always been a much more local market than is the case for crude oil. This is because moving natural gas long distances generally requires a pipeline. Seaborne shipments involve chilling gas which is expensive. Consequently, shipping costs for gas are typically a far larger proportion of the value of the commodity than is the case for crude oil, which is why you’ll hear reference to a global crude market but rarely one for natural gas.

However, this is beginning to change and the commencement of U.S. LNG exports last year is part of this new trend. Although the U.S. is currently an insignificant player, our exports are set to grow steadily in the coming years. Qatar is the world’s biggest exporter but is expected to be passed by Australia next year, which has ten LNG projects at various stages of production. One of the most extraordinary LNG projects currently underway involves liquefying natural gas that is sourced from beneath the seabed around 125 miles from the coast of Western Australia. Shell Australia is building a floating LNG facility called Prelude FLNG.

Prelude’s construction involves components from all over the world. The hull has been built in Geoje, South Korea, one of the very few shipyards in the world big enough to accommodate it. Other key components have been built in Malaysia, Dubai and France. Shell’s website has some interesting videos on the project.

Some numbers will illustrate: at 533 yards, it is longer than four English football pitches (or five American football fields). When complete, it will weigh as much as six of the largest aircraft carriers combined. It will be tethered permanently to the floor of the Indian Ocean, designed to withstand a 1 in 10,000 year typhoon (let’s hope that’s right). When chilled to -260 degrees Fahreinheit, LNG occupies 1/600th of the volume it would in a gaseous state. Prelude’s production could more than fully meet the needs of Hong Kong.

Shell’s Final Investment Decision (FID) to proceed with the project was made back in 2011 and construction began the following year. It’s safe to say the arrival of U.S. LNG exports on the market was not a factor that received much attention during Prelude’s planning. Natural gas prices around the world are lower than was the case when much of today’s LNG export facilities were initiated.

Only last year Woodside Petroleum cancelled a planned A$40BN FLNG project in the same area because of depressed commodity prices. But Shell has pressed ahead, and when in operation later this year Prelude will confront a changing world landscape. Japan has become a more significant buyer following the Fukushima nuclear disaster, which at one point led to a halt in output at all of the country’s nuclear power facilities.  China is also seeking to shift away from coal to cleaner sources of electricity generation.

Australian LNG exports chiefly supply China, Japan and South Korea. In fact, as the pie chart shows, imports of LNG predominantly go to Asia which in 2016 received 73% of the world’s total LNG shipments. The global trade in LNG grew 7.5% from 2015 to 2016, up from an annual growth rate of 0.5% over the prior four years. China’s imports jumped by 37% and India’s by over 30%. 72% of LNG trade in 2016 was conducted under long term contracts (defined as greater than four years). LNG trade requires substantial capital investment, so supply/demand certainty is sought by both sides. Altogether, 39 countries import LNG from 19 exporting ones.

Although there are enormous technical challenges in building an FLNG facility, there are some benefits too. Prelude’s location will allow it to draw over 13 million of gallons of water every hour from the ocean to help cool the natural gas it’s processing. And the fact that it’s offshore means that the permitting process need not be quite so concerned with the consequences of a catastrophic failure as with land-based facilities.

All these developments are leading towards increasing trade in natural gas and the concurrent development of a global market, pulling together the many regional ones.

We are invested in Cheniere Energy (LNG)

The Folly of Leveraged ETFs

Recent weakness in crude oil has spilled over into Master Limited Partnerships (MLPs). Some connection between the two is understandable, because part of the bull case for MLPs lies in growing shale output increasing demand for energy infrastructure. Lower oil prices dampen the enthusiasm for the idea that Exploration and Production (E&P) companies will be competing for sometimes scarce pipeline resources. For our part, we think the short-cycle nature of shale offers a substantial advantage for producers (see What Matters More, Price or Volumes?). MLP investors often feel they must have a view on crude oil before investing; because U.S. volumes are likely to rise in almost any price scenario, we think it’s less important other than over the short term perhaps. Shifting your MLP exposure around in response to oil prices is not a good long term strategy. If you have a view on oil, invest in oil.

Profiting from owning crude oil is harder than you might think. Many ignore storage costs. While these aren’t directly reflected in spot prices, they are most assuredly part of the return from owning securities linked to the price of oil. The costly “rolldown”, by which the expiring near futures contract has to be regularly rolled into the next, higher priced one simply reflects the cost of storage. The approximately $1.20 per barrel price difference between May and August crude futures is largely due to the cost of storage for three months. Think of it as the time value of money applied to crude oil.

Exchange traded products linked to oil have a checkered past, which some think shows the need for a better solution aimed at those who would like to profit from their view of oil prices. ProShares, a purveyor of leveraged ETFs, has come up with a doozy.

Oil has been pretty volatile over the last few years. From its peak in 2014 its spot price dropped by 75% through February 2016, before doubling over the next year. If your version of excitement is a commodity price that gyrates wildly, you need look no further than oil futures.

But some find this tame. Downhill skiing may appear sedentary to those who insist a true mountain experience must be preceded by a helicopter ride to find real deep powder. But the kite skier needs a three-dimensional snow experience; if it’s not dangerous it’s not worth the trouble.

The kite skier is the type of buyer attracted to the ProShares UltraPro 3x Long  Crude Oil ETF, designed for those wanting to profit from rising crude oil (Ticker: OILU). And because excitement need not be limited to a rising market, they also have a bear market version (Ticker: OILD).

These two investments share a couple of traits with kite-skiing, in that they’re dangerous and not everyone involved will have a good time. OILU is designed to move each day by three times the percentage move in the Bloomberg WTI Crude Oil Sub-index. In order to maintain this 3X exposure to daily moves, OILU will need to rebalance its holdings every day. Without going into the messy details, this introduces the insidious nature of the use of leverage, in that rebalancing will always necessitate trading in the direction of the market. Following a rise in crude, they’ll need to buy more oil futures to bring their exposure back up to 3X. When it falls, they’ll need to sell oil to bring their exposure down to 3X.

As you can appreciate, if oil goes up and down but doesn’t make much overall progress, the buy high/sell low rhythm of re-hedging will relentlessly eat away at the holder’s value.

The last couple of years were interesting to say the least for oil traders. It’s possible to simulate how OILU and OILD would have performed for their holders over this period. The simulation omits fees and transactions costs, so the real results would have been a bit worse.

It might not surprise to learn that OILU lost money when oil went down. It is after all designed to make money if oil rises, so if your forecast is wrong OILU will not be your friend. Crude peaked in April 2014, and OILU would have lost 90% of its value by Christmas. Its chart looks rather like a kite skier suffering cardiac arrest. Although it’s hard to see, I can report that OILU did double in price when oil began to rally, albeit after falling 95%.

More surprising is that the bear market version, OILD, ultimately fared little better. Although crude oil is roughly half its value from three years ago, the OILD holder who made this correct forecast nonetheless saw his investment lose 70% of its value.

The point here is that 3X levered ETFs are not for those who develop an emotional attachment to their securities. The longer your holding period, the greater the certainty that you will lose money. Therefore, the optimal holding period is correspondingly as short as possible – or, if you’re not a kite skier, no holding period at all. Leverage means you care not just about the accuracy of your forecast but also about how quickly it happens. Predicting the near term path of prices as well as their ultimate resolution is how the over-confident are separated from their money. Leveraged ETFs are designed with the expectation that rebalancing will inexorably drive their value to zero.

The seductive and eye-catching part of the chart is of course the eightfold and eventually tenfold increase in the price of OILD. It was most definitely possible to make a lot of money from OILD. It required the possession of both oil price insight and exquisite timing, but for those blessed with both a healthy gain was to be had.

The problem is that, since few could have had such luck, over the three year simulation the typical holder lost money. Because ETFs don’t have a fixed share count some might quibble with this assertion; buying might have been substantial at low prices and inconsequential at high ones. It is unknowable of course, but in securities markets activity inevitably rises with prices. There would have most likely been many more buyers of these levered ETFs when they’d risen, further increasing the ranks of ultimate losers.

So you have a product that will be profitable for some but unprofitable for many and certainly for most. Should it even exist? How should we regard the supplier of something of whom the customers will for the most part suffer financially from their purchase? Is ProShares part of the efficient channeling of savings towards productive capital formation, the reason public capital markets exist? Or are they the casino owner, profiting from customers who on average will be richer by not entering?

And what’s wrong with that? Lottery ticket buyers, even the least financially sophisticated, pretty much understand that the odds are against them. In willful defiance of classical economic theory, lotteries nonetheless thrive even though the customers are selecting negative expected outcomes. They do this because the hope of winning, the dreaming of how that payoff would transform life, itself comes with positive utility. No ticket, no dream. Hope has value.

Is it therefore also true that users of ProShares products similarly comprehend the adverse odds they face and nonetheless derive utility from the hope of profit? Or is it more likely that they don’t perform the analysis above, and attribute any financial outcome to their expressed opinion rather than poor choice of product? In this case, the buyers of ProShares 3X products are less financially sophisticated than the lottery buyers they might regard with disdain. When waiting in 7-11 to buy milk while a customer ahead purchases a lottery ticket, the ProShares buyer should seek his financial advice. He might learn something. Lottery ticket buyers have more realistic expectations than ProShares buyers.

The ProShares prospectus details various dire outcomes that may result from a purchase. But of course nobody reads prospectuses, so they are legally compliant if not informative. However, shouldn’t there be a presumption that the typical holder of a ProShares product will profit if his underlying view is correct? What use is a supplier of financial products that largely destroy value? Demand certainly exists, as ProShares proudly notes on its website the $27BN in such ETFs they offer. But size of capital raised doesn’t prove intelligence by the investors, as the hedge fund industry routinely proves.

If some regard “ethical financier” as an oxymoron, it might be in part because of the values behind the offering of 3X leveraged ETFs. Just because something can be created doesn’t mean it should be.

The Slow Shift in Power

The U.S. produces electricity from diverse sources; burning coal and natural gas each provide just under a third of our needs (natural gas is steadily displacing coal, which is good for those MLPs that transport, process and store natural gas). Nuclear is 19%, with the rest being other renewables of which hydro is the biggest. Solar from all sources (which includes both utility scale production as well as rooftop panels that supply back to the grid) is currently 1.4%. In 2016 we used around 4,100 TWH (Terrawatt Hours).

To explain the dizzying numbers: One Terrawatt (TW) is 1,000 Gigawatts (GW). One Gigawatt is 1,000 Megawatts (MW). Capacity is measured by output capability, while use is measured by quantity consumed per hour. So a 100MW power plant could supply 100MWH if it ran at 100% capacity for sixty minutes.

For those who forecast big shifts in how the U.S. generates electricity, year-to-year change is disappointingly slow. This is because the net additions to electricity generating capacity each year are only a small fraction of total capacity.

Last year we added 15 GW of net new generating capacity, the biggest in five years including a decent jump in wind and solar. Also notable was the ongoing retirement of coal plants. As the third chart shows, this is likely to continue because older power plants are more likely to be coal-burning. The challenge with wind and solar is that it’s not always windy and sunny, and since commercially viable, large scale storage is still ahead of us, utilization is lower for these categories than others.

To illustrate how slowly the existing electricity generation capacity changes, consider these figures: total generation capacity is 1.1 TW, or 1,100 GW. Very approximately, 1.1TW of capacity could theoretically produce 9,600 TWH in a year if everything ran at 100% (i.e. 1.1 X 365 days X 24 hours in a day is 9,636). So our consumption means we used 42% of this theoretical capacity. Since power needs fluctuate depending on the time of days as well as the seasons, and facilities need to be shut down for periodic maintenance, the industry is more efficient than this sounds.

But it puts the 15GW of new capacity in perspective since it represents around 1.5% of the installed base.  Even this overstates its impact because of the lower utilization rates of wind and solar.

Change is surely coming to how we source our power. Future generations will almost certainly rely far more heavily on solar. But over the next decade or so, change will appear slow.