The gas glut is unlikely to last

4 Sep 2010 by Jim Fickett.

At current prices, most shale gas production is almost certainly unprofitable. Further, the excess supply from shale has caused conventional producers to reduce drilling. I will be surprised if we do not see the excess supply disappear, and gas prices rise substantially, by the end of 2011.


US shale gas is all the rage, past, present, and future. Note this US Energy Information Administration history and projection of gas production:

The current gas glut is, to a large extent, due to the rapid expansion in drilling for shale gas, and that glut has driven down prices. Will that trend reverse? The key question is whether production of shale gas is profitable at current market prices.

This all matters for pricing utilities (a favorite in the current emphasis on dividend stocks), for other energy stocks (will gas displace coal for power plants?), for renewable energy (will the US undertake a major program for gas-powered vehicles, or will it concentrate on wind and solar power, and electric cars?), and for politics (can the US really reduce oil imports?).

Much has been written about unconventional (most importantly shale) gas in the last few years. I have an Unconventional gas background Reference page, and it is easy to learn a lot pretty quickly with the help of Google. So I will only say, by way of introduction, that

  • New drilling technology has greatly changed the overall picture
  • There is an optimistic crowd that thinks the US has a 100-year supply of gas, that gas is in oversupply for the long term, and that gas will remain very cheap
  • And there is a skeptical crowd that thinks the resource is overstated, the oversupply is due to temporary distortions, and shale gas is much more expensive to produce than now appears to be the case

I've discussed the reserves question elsewhere. This post is about the economics of current shale gas production, in particular, whether production is profitable at current prices, and whether the oversupply will continue.

A broad, ongoing debate

Many reporters take the optimistic view as a given, but within well-informed circles the debate is quite active. Platts, the well-known energy information service, writes this in describing their upcoming “Unconventional Gas” conference:

unconventional gas is seen as perhaps the most exciting prospect in years.

At least, that’s the promise — but what is the reality? Does it really have the potential to transform countries’ energy mix and security of supply? Is the industry up to the technological challenge? And just how workable are the economics, especially given the recovery rates?

A history of feast or famine

Before getting into the particular arguments, it is worth keeping in mind that the gas market in the US has a long history of swinging between feast and famine. This passage, from a recent MIT report entitled The future of natural gas, describes it well:

The somewhat erratic history of natural gas in the U.S. over the last three decades or so provides eloquent testimony to the difficulties of forecasting energy futures, particularly for gas, and is a reminder of the need for caution in the current period of supply exuberance.

This history starts with a perception of supply scarcity. In 1978, convinced that the U.S. was running out of natural gas, Congress passed the Power Plant and Industrial Fuel Use Act (FUA) which essentially outlawed the building of new gas-fired power plants.

Between 1978 and 1987 (the year the FUA was repealed) the U.S. added 172 Gigawatts (GW) of net power generation capacity. Of this, almost 81 GW was new coal capacity, around 26% of today’s entire coal fleet. About half of the remainder was nuclear power.

There then followed a prolonged period of supply surplus. By the mid 1990s, wholesale electricity markets had been deregulated; new, highly efficient and relatively inexpensive combined cycle gas turbines had been deployed; and new upstream technologies had enabled the development of offshore gas resources. This all contributed to the perception that natural gas was abundant, and new gas-fired power capacity was added at a rapid pace.

Since the repeal of the FUA in 1987, the U.S. has added 361 GW of power generation capacity, of which 70% is gas fired and 11% coal fired. Today, the name-plate capacity of this gas-fired generation is significantly underutilized.

By the turn of the 21st century, a new set of concerns arose about the adequacy of domestic gas supplies. For a number of reasons, conventional supplies were in decline, unconventional gas resources remained expensive and difficult to develop, and overall confidence in gas was low. Surplus once again gave way to a perception of shortage and gas prices started to rise, becoming more closely linked to the oil price, which itself was rising. This rapid buildup in gas price, and perception of long term shortage, created the economic incentive for the accelerated development of an LNG import infrastructure.

Since 2000, North America’s rated LNG capacity has expanded from approximately 2.3 Bcf/day to 22.7 Bcf/day, around 35% of the nation’s average daily requirement. This expansion of LNG capacity coincided with the market diffusion of technologies to develop affordable unconventional gas. The game-changing potential of these technologies has become more obvious over the last three years, radically altering the U.S. supply picture. The LNG import capacity goes largely unused at present, although it provides valuable optionality for the future. We have once again returned to a period of supply surplus.

This cycle of feast and famine demonstrates the genuine difficulty of forecasting the future, and underpins the efforts of this study to account for this uncertainty in an analytical manner.

Current production, unprofitable, continues due to lease requirements

The clearest evidence that producing shale gas is not profitable at current prices is that several oil and gas company CEO's hold that opinion.

For example Chevron, speaking both through CEO John Watson and through Vice Chairman George Kirkland, has recently stated that the company is not interested in following the crowd into US shale plays, because they do not see such ventures as profitable. John Richels, CEO of Devon Energy (on my short list of strategically brilliant gas companies), is of the opinion that many producers are losing money, and are only being kept alive by new capital infusions. Lest I convey the wrong impression, let me say that both Chevron and Devon are interested in shale gas, they just think the economics are not right at present – the land rush prices were too high and the present market price of gas is too low.

Why then, if producing shale gas is currently not profitable, is there a frenzy of drilling? Because most leases require the operator to have commercially producing wells within 2 to 3 years of leasing, and the big rush in leasing took place in 2007 and 2008. Aubrey McClendon, CEO of Chesapeake Energy and an evangelist for shale gas, was recently quoted as saying,

If I had my druthers we’d be running no more than a couple [rigs] … You’d be surprised how much drilling is not voluntary today.

Profitability, accounting and geology

At the same time that some CEOs are saying the production of shale gas in the US is currently unprofitable, many are saying that it is. And the differences run deeper than whether some companies found better deposits. Engineers and analysts can look at the same companies, or even at the same wells, and come up with different opinions. How is that?

The essence of the difference lies in basic accounting – the capital costs are amortized over the expected life of the well, and are balanced against the estimated revenue from the total amount of gas expected to be produced from that well (“expected ultimate recovery”, or EUR). So costs are lower if you forecast longer well life and higher production. But all shale gas wells are young; no one knows typical well lifetimes yet; and EUR is a guess. Hence it is easy to come up with different answers.

What is clear is that shale gas wells deplete much faster than wells in conventional deposits – each year's production is typically about 45% less than the previous year's, unless expensive treatments are used to further fracture the rock. This 45% compares to something like 25% in conventional wells. So, according to the skeptics, when companies apply standard models to the new wells, they may be fooled into predicting excessive well lifetime and EUR.

Arthur Berman, a petroleum geologist in the skeptical camp, says, for example,

I recently grouped all the Barnett wells by their year of first production. Then I asked, of all the wells that were drilled in each one of those years, how many of them are already at or below their economic limit? It was a stunning exercise because what it showed is that 25-35% of wells drilled during 2004-2006-wells drilled during the early rush and that are on average 5 years old-are already sub-commercial. So if you take the position that we’re going to get all these great reserves because these wells are going to last 40-plus years, then you need to explain why one-third of wells drilled 4 and 5 and 6 years ago are already dead.

This is the main issue, but there is other evidence of creative accounting.

Ben Dell, an analyst at Bernstein Research, finds “a growing discrepancy between the internal rates of return (IRR) presented in corporate presentations and company reported ROACE (return on average capital employed)”. He does not believe that all the costs are being factored into the advertised cost of production.

John Dizard, an investment columnist with the Financial Times, interviewed a large number of experts in the field and concluded,

American shale gas companies assert that they can profitably produce gas from formations such as the Marcellus in Pennsylvania for $2 or $3 per mcf (thousand cubic feet). But in the fine print you find that represents only the “finding and development” costs, which are only a quarter to a third of the total needed to get a molecule to market.

For some, the rose-tinted view is required for survival

Why would companies be understating their costs? According to Allen Brooks, of the energy investment bank Parks, Paton, Hoepfl & Brown, (1) they have to drill in order to retain their leases; (2) they need capital to drill; (3) in order to raise capital, they need to show rising reserves; and (4) reserves, defined as gas that can be produced at current prices, don't look good unless current wells are profitable.

In other words, it is not just a matter of booking higher profits, for many it is a matter of survival.

Bottom line, dollars and years

In sum, the evidence is pretty convincing that production at current prices is not profitable, that production will therefore drop, and that prices will have to rise. But, as every investor who likes facts better than hype knows to their cost, unsustainable activities can go on for a long time. If the above interpretation is indeed right, then as long as high volumes of new capital are coming in, both the motive and the means will be present to underestimate costs.

Nevertheless, there is some evidence that a change is not too far off.

First, Henry Groppe, a well-known forecaster with the experience of many booms and busts, takes the emphasis off of shale gas, and notes that, out of the spotlight, a major force is reducing production overall. He says that despite the huge push, shale gas is only 6% of US production and, in the other 94%, drilling has greatly decreased, as those producing conventional gas sit out the glut. Conventional wells deplete at about 25% per year, so that 94% of production has been dropping, and will continue to drop, significantly. This negative will, before too long, outweigh the increase in shale gas production. Note that this is entirely consistent with the EIA forecast shown in the chart at the beginning of this post.

Second, as mentioned above, there was a land rush in 2007-2008 and, for most of those leases, the requirement was for commercial production within two to three years. So much of the pressure for more drilling should abate over the course of 2010-2011.

Overall, I think the most likely scenario is that prices will rise significantly by the end of 2011. But continued new investment might change that, so I would not make a speculative bet on near-term gas futures. What I would consider carefully is long-term stock holdings that would benefit from higher gas prices.

How much might prices rise? Assuming that most sources mentioning prices are referring to the standard Henry Hub spot price, it looks as if there is reasonable consensus among the skeptics that prices need to rise at least to $6, and probably more like $7.50 per thousand cubic feet (or, equivalently, per million Btu), from the current $4 or so.

(Note: I hope to revisit this topic now and then, so a rough first draft Reference page, Shale gas economics, has been added.)