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

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

 

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

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 100^th 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 1/600^th 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)