Natural gas investors are making a mistake. Natural gas and gas-weighted E&Ps are in the media for many reasons now and attracting capital. Unfortunately, it is too early to invest in this sector. Sentiment may be bullish, but the math is not. Let us look at the commodity, then at some of the equities.
Natural Gas Production
If you are invested in this sector, you already know that there are four major issues being priced into the supply and demand future for domestic NG (with many other minor but important variables):
- Shale: new production economics, regions, and technology
- Imminent LNG Export: Significant volumes, long timeline
- Coal-fired Power Replacement: Gradual, large, predictable
- Liquids: rising gas production as an oil and NGL byproduct
Nearly every demand component will grow meaningfully as far as the eye can see. Industrial demand is further on the horizon but will also be significant, and home heating is not going away. Even CNG vehicles may eventually add an increment.
But here is the problem. Supply growth will smother all those sources for a long time. Current consensus is for flat to slightly increased domestic production in 2014. But the shale revolution is the story of supply growth that was repeatedly underestimated.
Unfortunately, hindsight is about 20/80 in this case. Perhaps memory is also warped. The individual rig and well productivity was there for all to see, but there was a significant lag in aggregate output during chapter 1 of the shale revolution. The basic story since 2007:
With the first collapse in rig counts in '09, a production decline was expected, but it never came. The plateau was just a head fake, and a sharp rise in output resumed. We have seen another rig count decline in 2012, and production growth seems to have paused again in 2013. But the problem in '09 proved to be the large backlog of wells that were drilled but not yet producing. And we have the same problem again, with as many as 2,000 wells in the northeast region that are not yet producing due to a variety of factors that are being gradually addressed.
Obviously drilling is necessary for natural gas production. But what was a rig accomplishing in 2007, in 2010, and today? This is the essence of the argument. For a rig count to mean something about production, we need to know how many rigs are working and how much gas they are developing.
We forget that the Haynesville was a world class discovery in its day, and that in 2010 producers were proudly announcing 6 BCF wells drilled in 45 days. That means that if a rig had no downtime, it might drill as many as 8 wells per year, developing 8 x 6 = 48 BCF. And it was the best opportunity for many drillers. Better than the Barnett or the Fayetteville Shale.
But the resource opportunities and the producers have improved in the meantime. Look at the impressive learning curve for a producer in an old shale play. Here are the stats that Southwestern Energy (SWN) reports in their core play, the Fayetteville Shale:
This is just continuous improvement in technology and understanding in an existing formation. Progress moves much faster in the early stages of development in a new formation. Here are the current Cabot investor presentation slides showing their Marcellus drill times and costs, along the annual increases in reserve estimates:
Compare the rig productivity from the 2010 era in the Haynesville of about 50 BCF per year to the current Cabot numbers
14 days drill time x 14.1 BCF per well = 368 BCF per year per rig
This comparison isn't quite accurate because these drill times do not include rig mobilization time, but even that is improving substantially with pad drilling. If we considered their best drill time of 8 days, and assumed 4 days of rig downtime, we still would get 2.5 wells per month, or over 400 BCF per year per rig. This is surely far above the average for the play, but the rate of improvement is high for all operators.
Look at the other big names drilling in the Marcellus to confirm these numbers. Chesapeake (CHK), Southwestern , Ultra (UPL), Range (RRC), Antero (Private), Seneca (NFG), and others. Most are not quite achieving Cabot's results, but they are only off by percentages, not multiples.
The comparison isn't as simple as saying a rig is 8X more productive today. But don't overcomplicate it either. Many producers are reporting these kinds of results in the Marcellus and the expectation of further improvements from innovations already being field tested, and no shortage of drilling inventory and acreage.
About 28 TCF is produced in the US annually now, and if one rig can develop as much as 400 BCF, it only requires 70 rigs to replace our produced volume. It sounds crazy, especially considering that the pace of improvement is still rapid and rigs may be achieving better results soon.
We also know that a significant amount of natural gas is produced in association with oil, and oil production is both large and growing in the US. It varies by basin, but it might average 15-20% across all basins, depending on how wells are classified. With production above 7 million barrels per day now, and steadily rising that would imply 10 to 15 BCFD or more of associated gas production will be coming from this source in the future, a very meaningful contribution.
Natural Gas Liquids are also a valuable commodity of course, and they must be stripped from the gas stream in processing facilities and transported separately in most cases. MarkWest is a large operator of these NGL plants in the Marcellus Shale. Look at this slide from their current presentation. It looks like they see NGL supply in the northeast growing from about 270 KBPD in '13 to about 930 KBPD in '18.
Another reason some investors find it hard to believe that production can grow so much is the persistent myth that gas is priced below the cost of production. The tiring axiom, "The cure for low prices is low prices." has been repeated ad nauseum. It is not true for LCD televisions, and it will not be true about $4 natural gas. Not for a very long time. Instead, production costs will keep declining and high cost producers will die off.
Each producer would have you believe that everybody in the industry is losing money (except they themselves). Consider this next slide. It is from Ultra Petroleum's current presentation, but you will find a hundred similar slides from other operators. It seems to suggest that they are the lone operator that can profit on $4 natural gas.
Standing next to a fat person makes you look thin. UPL has done a fine job fooling readers into accepting a very incomplete, and very oily, peer group. Comparing Ultra Petroleum to Whiting Petroleum (WLL) on costs per mcfe is only something you would do if you literally did not understand the difference between oil and gas. UPL is a dry gas producer. They should be compared with other dry gas producers like Southwestern Energy or Cabot.
What Is Going To Happen?
Gas demand will steadily grow, but gas production will grow faster. Producers, and investors, will initially put on a brave face and hope that it is temporary, plan to stay the course, and let LNG exports soon balance the market and connect US gas prices of $4 with world prices of $8 to $18 MCF. And the faithful investors who hold on will reap their beautiful reward. Indeed, if it were just a question of one shoulder season back in the $2 range, I too would place that bet.
But investors should recognize:
- A prolonged price decline to the $3 mark is not priced into E&P equities now.
- Structural oversupply could overwhelm the only elastic demand source, coal replacement, for a long time. The only price floor below that is the cash cost of dry gas production, below $2.
- Regional bottlenecks can drastically reduce spot prices relative to Nymex Henry Hub. The entire northeast is now at risk for this seasonally.
- If the Marcellus/Utica/Upper Devonian complex is really capable of producing many times the current rate (it can!), then even 10 BCFD of incremental demand can be met by supply increases from these prolific formations. The holders of dry gas acreage elsewhere, with half-cycle costs above $2, may not recover. It isn't even certain that the Haynesville has a place in the supply stack for a long time to come. Proximity to markets or LNG terminals will not overcome a $1/MCF cost disadvantage.
Will gas go back below $3? It is possible, but very dependent on weather. A much warmer than normal winter would send gas into the basement, but we saw in 2012 that gas prices below $3 generate a tremendous incentive for power producers to switch from coal, and this can absorb a substantial oversupply. The facts would more accurately support a claim that gas will have a difficult time staying above $4, even if weather is favorable. Much of the existing electric generation demand would be lost to coal, and $4+ prices will be attracting drilling in the most economic basins.
What Investors Can Do
Do not buy unhedged producers, dry gas producers, or remote reserves. I think the Rockies and Northern Canada are too risky. The transport alone could cost more than drilling. That rules out Encana (ECA) despite their fantastically deep acreage inventory and extensive hedges. Even the Haynesville would need to see big efficiency improvements to be competitive. I like to pick on Ultra Petroleum, because they are popularly viewed as a very low cost gas producer. But they are dry, with most production in the Rockies, and have very few hedges beyond 2013. They are the most optimistic and vocal about an imminent gas price recovery, but they will not likely outperform peers in any scenario.
Cabot is well positioned because it has the best Marcellus dry gas acreage on planet earth, based on well performance to date. And Range Resources also has great acreage, in both dry and wet areas of the Marcellus. Southwestern also has made a good transition to the dry Northeast Marcellus, with solid recent well results tracking above a 16 BCF decline curve.
But the thesis here is that all the gas producers are potentially overvalued now because the forward price strip is too high, and the production may be so strong that even the relief valve of LNG exports may not bring prices up until a sufficient number of terminals are in service.
Hedging or shorting natural gas futures or futures options is not recommended. Gas is very volatile, and subject to other unpredictable forces, mainly weather. A cold winter can certainly lift gas prices, even in the scenario I suggest above. I do invest in gas futures and futures options, but cautiously and with many years of experience. I think gas will have a very difficult time staying above $4 throughout 2014 and perhaps longer. With unfavorable weather, prices can quickly fall into the $2's by spring.
Look instead downstream to the transportation and processing (EPD, MWE) that could have pricing power as the bottleneck for many years. Consider pipelines and utilities and gassy independent electric power producers. Avoid coal producers, and look to other end users that will enjoy an advantage from cheap feedstock. That advantage will continue much longer than most believe.
If you currently own domestic gas-weighted equities, or are long gas or the gas ETF (UNG), consider hedging or at least stress testing your holdings against some hypothetical low prices. Everyone knows that gas is traditionally volatile due to weather, but a combination of bearish weather and overproduction would require a period every bit as long and painful as 2011 when gas broke through $2. And don't hold a losing position on the belief that LNG exports will bring certain relief as soon as Cheniere Energy's first liquefaction train is operational in 2015-16.
Additional disclosure: I hold both long and short futures and futures options in Nymex Natural Gas and adjust them frequently.