The title of this week’s issue isn’t a prediction–it’s reality.

Before you decide I’m crazy and close this e-mail, understand that I’m well aware that near-month natural gas futures traded on the New York Mercantile Exchange (NYMEX) are priced just over $4 per million British thermal units. And I’m aware of the prevailing view that natural prices will likely remain near record lows because of elevated levels of stored gas.

Those pundits are at least partially correct: US natural gas storage levels are above the five-year average and, thanks to mild spring temperatures, have increased at a faster-than-normal pace in recent weeks.

I’m also not the first to tell you that the discovery and rapid development of several major unconventional natural gas shale fields over the past few years has revolutionized the industry and transformed the US into the world’s biggest natural gas producer. This is an astounding shift. Less than a decade ago, most energy industry analysts would have told you that US gas imports in the form of liquefied natural gas (LNG) were set to soar as domestic production began an inevitable decline. Now US LNG terminals sit idle, and there’s talk of passing laws to encourage the use of natural gas in new markets such as transportation.

North America’s strong gas production outlook, high storage levels and weak NYMEX gas prices seem to be completely at odds with the surge in drilling activity that’s occurred since last summer.


Source: Bloomberg

This graph depicts the US gas-directed rig count–the number of drilling rigs actively targeting gas in the US–and gas prices going back to 1990.

A cursory examination shows that changes in the price of natural gas tend to lead changes in the rig count by a few months. That’s because rising gas prices make the economics of drilling for natural gas more attractive and offer an incentive for producers to drill more aggressively.

The drilling cycle is historically self-correcting. Higher prices ultimately mean more drilling activity and higher production, boosting supplies and increasing storage levels. Meanwhile, lower prices have traditionally reduced production and normalized US gas inventories.

But the cycle over the past year and a half has been unusual. US gas prices hit their highs in early July 2008 and declined more than a third by the last week of August. However, it took nearly two months for US gas producers to respond to the decline in price; the US gas-directed rig count hit its highs in late August of 2008 and remained on a high plateau level for nearly a month. The first declines in activity were relatively modest; big producers like Chesapeake Energy (NYSE: CHK) announced a slowdown in activity in conventional fields that have a higher cost of production.  In fact, the US rig count didn’t rapidly decline until late November and early December of 2008.

That part of the cycle played out exactly as one would expect. However, what looked like a normal cycle in early 2009 completely broke down over the summer. Even with US gas storage levels in danger of hitting maximum capacity and weak demand, US drilling activity began to re-accelerate.

Even more puzzling, the US gas-directed rig count has picked up in 2010 even though gas prices fell from $6 per million British thermal units at the beginning of the year to less than $4 per million British thermal units a few weeks ago. The rig count now stands nearly 50 percent above the nadir reached in July 2009.

Many also find it paradoxical that stocks leveraged to natural gas have fared reasonably well over this period. Since July 1, 2009, natural gas prices have decline roughly 5 percent. At the same time, my proprietary TES Natural Gas Index–an index comprised of natural gas producers, equipment and services firms–has rallied 31.5 percent. Among the top performers in that index are land-focused contract driller Nabors Industries (NYSE: NBR), whose shares are up 34 percent, and fracturing proppant manufacturer CARBO Ceramics (NYSE: CRR), which is up 122 percent.

Some pundits have taken the easy road, dismissing the rising rig count and falling gas prices as irrational and unsustainable. But I’ve found that phenomena which appear irrational at first glance often have a logical explanation–the gas market is no exception.  

The actual value of natural gas produced from some of the most important US shale gas fields is currently running at over $7 per thousand cubic feet. This seemingly contradicts what we hear about natural gas prices in the financial media–after all, spot gas prices are near eight-month lows and the 12-month strip stands at $5 per million British thermal units. But these depressed prices represent the value of dry, pipeline-quality gas comprised almost entirely of methane.

Raw natural gas produced from a well comprises far more than just methane. Raw gas often occurs naturally with a series of hydrocarbons known collectively as natural gas liquids (NGL). Although the popular media and pundits on financial television rarely mention NGLs, these adjuncts commodities are crucial to understanding the apparent disconnect between gas prices and the US gas-directed rig count.

The key point to remember about NGLs is that they tend to trade at prices that track crude oil more closely than natural gas.


Source: Bloomberg

In this graph, the price of a barrel of NGLs is based on what’s considered a normal mix; ethane is the largest component followed by propane and butane. NGLs and oil aren’t interchangeable, and the two commodities don’t always move in complete lockstep. Nevertheless, the correlation is undeniable. 

As you can see, the value of a barrel of NGLs has largely followed oil prices higher over the past year, rising from barely $20 a barrel in late 2008 to around $50 a barrel today. This stands in stark contrast to the action in natural gas prices.

For producers targeting gas fields rich in NGLs, the value of methane is only one component of the total value of any natural gas produced; you cannot simply look at NYMEX natural gas prices to gauge drilling activity levels.

Gas produced from the Marcellus Shale in Appalachia is rich in natural gas liquids (NGLs), especially in the play’s western reaches. Range Resources Corp (NYSE: RRC) is one of the largest producers in the Marcellus and one of the largest acreage holders in the play. At a recent conference, the company’s management broke down the actual value of 1,000 cubic feet of wet natural gas produced from the Marcellus.

Source: Range Resources

To calculate this table Range assumed crude oil traded at $75 a barrel, implying a barrel of NGLs would be worth $42 a barrel–levels below the current market price for both crude and NGLs. The company also assumed that Henry Hub Gas Prices were $5 per million British thermal units, slightly above the current 12-month strip.

In addition, the company adjusted prices for basis differentials, or location-based price differences for oil and natural gas.  

For every 1,000 cubic feet of gas Range produces, the company produces 900 cubic feet of dry natural gas, 2.45 gallons of mixed NGLs and 0.013 barrels of condensates–hydrocarbons that are heavier than NGLs and typically trade at a premium to NGLs and a discount to crude oil. If we add up the value of all these components in the typical Marcellus gas stream, Range is realizing $7.28 per thousand cubic feet, roughly 50 percent higher than the current NYMEX-traded price of gas.

When you consider that Range’s total operating and transportation expenses in Appalachia are between $0.75 and $1.75 per thousand cubic feet of gas, it’s clear that the firm’s wells are extremely profitable despite low gas prices.

Producers in the Marcellus and other wet gas fields aren’t responding to lower natural gas prices by reducing their drilling activity because these companies aren’t exposed to depressed gas prices. Instead, many of these so-called gas producers are targeting liquids that trade at crude-like prices.

Cheap Gas and Horizontal Oil

NGLs are a major driver of the rising US rig count, but they’re not the sole factor at work.

Consider the case of the Haynesville Shale in Louisiana and East Texas. Haynesville gas is found deep underground and at high temperatures and pressures–conditions that tend to limit the presence of NGLs and condensate. The deposit doesn’t contain oil, nor does the shallower Bossier Shale. But despite the lack of NGLs, drillers have been extremely active in the Haynesville over the past year; Louisiana’s gas production is growing at a rapid clip. 

That’s because the Haynesville wells are prolific. The Haynesville Shale is thick and contains a great deal of gas. In addition, the extreme pressure in the field means that Haynesville wells produce gas at unusually high rates–natural underground pressures literally force gas into a well and to the surface at a tremendous pace. Because wells are so prolific, the cost of producing natural gas in this region is among the lowest of any play in North America. Even with natural gas prices at $4.75 per million British thermal units, Haynesville producers can earn a solid return on investments in the region.

Finally, investors often associate the terms “shale” and “unconventional field” with natural gas rather than crude oil. But several major shale fields in the US produce crude oil or some mixture of crude oil and NGLs. Drilling activity in these plays is strong thanks to the high price of oil.

Oil produced from shale plays is conventional crude oil, often of similar or better quality than West Texas Intermediate (WTI) crude oil. Producers target shale oil using the same basic technologies used to produce natural gas from fields like the Marcellus and Haynesville–a combination of horizontal drilling and hydraulic fracturing.

One of the first shale oil plays targeted using these technologies is the Bakken Shale located in parts of North Dakota, Montana and across the Canadian border in Saskatchewan. Producers in this region have drilled some of the most prolific onshore US oil wells in decades, and oil production in North Dakota has roughly tripled since 2004–largely because of drilling in the Bakken.

But the Bakken isn’t the only shale oil play in the US. Among the most promising new finds is the Eagle Ford Shale in southern Texas.

There are three distinct windows in the Eagle Ford shale. The southernmost part of the play is extremely deep, under high pressure and contains dry natural gas. Just to the north of the dry gas window is a wide swath of shale that’s a bit shallower and contains mainly wet gas. And most interesting of all, just to the north of the wet gas window, the Eagle Ford produces primarily crude oil and some gas.

The number of rigs drilling for oil in the US has more than doubled in the past year and is significantly higher than it was in mid-2008, when oil traded at nearly $150 a barrel. Even more impressive: The oil-directed rig count now stands at the highest levels in more than 20 years.

Liquid Assets

There are a few different ways to play the boom in drilling activity directed natural gas liquids and crude oil. One is, of course, to focus on companies that own acreage in these wet natural gas and shale oil plays around the US and/or Canada.

Another even more levered play: Services and drilling firms with the advanced rigs and technical know-how to drill these complex fields. Shale fields often require drilling deep wells with lengthy horizontal legs. Such wells also require multiple fracturing stages to render them economically producible. In other words, producers require powerful equipment; every horizontal well drilled in the US requires the purchase of far more services and equipment than a vertical well in a conventional field.

But income-oriented investors should also consider buying master limited partnerships (MLP) with exposure to natural gas gathering, processing and fractionation. Producers will need access to processing plants to separate valuable NGLs from the gas, fractionation plants to separate NGLs into their constituent components and terminals and storage facilities.