I’ll toss in a few personal experiences from the cheap seats. “…this price is below the cost of production for many of these new wells.” I have no doubt you understand the distinction but for others: I’m sure by “production” what is really meant is “development cost”. It actually cost relatively little to produce most NG wells. It might cost Company A $0.30/mcf to produce its NG wells. So even when they are getting $2/mcf they are realizing $1.70/mcf positive cash flow. Which isn’t an indication of profit. It might have cost the company $2.50/mcf to develop those reserves. Also a minor point about NG prices, Just because Henry Hub may be $X/mcf that does the company is getting that price. I have a well in Cameron Parish with it sales price tagged to the HH index. But when HH got town to almost $2/mcf I was getting that price. I had to pay pipelines $0.42.mcf to get the gas from my well to HH. So last April I was selling for $1.62/mcf. Still positive cash flow. We had reduced production 50% but even if prices increase anytime soon the well will never pay back its development costs. Found some NG but due to drilling problems the well cost twice as much as projected. As we say there is the plan and then there’s what actually happens. LOL.

This explains the confusion some folks express as to why companies don’t reduce their NG production in the face of lower prices. Some companies, like mine, can do so. But many companies can’t: between paying down debt and covering overhead of ongoing ops they need all the revenue they can get even if that means selling below cost. Which goes a long way to explain: “…the rapid drop-off in drilling activity since 2009 has yet to result in any decrease in production.” There’s also a more subtle factor at play: “Drilling a natural gas well takes time, typically from 3-6 months from spudding until completion.” True but the overall process leading to putting a new well on production is much longer. It may have taken Company A two years to create Prospect X as well as chasing a number of leads that didn’t turn into viable prospects. Then add another year to lease the acreage and do the title work. Title work: just because you’ve sign a landowner to a lease doesn’t mean you own it. Given multiple transfers over many decades it can take 2 to 6 months for title experts to confirm a company’s ownership rights. And then comes finding partners. Many companies don’t drill 100%. My company typically takes only a 50% working interest. It might take 3 months to a year to find other investors to go in on the project. Once done a drill rig has to be scheduled. Depending on activity in the area that might take 2 to 6 months. And now the well is drilled and you found a nice NG reservoir and you run production casing. But the well isn’t close to coming on line. The drill rig is moved off and a completion rig is moved in: add another month or several for that to happen. And if it’s a fractured shale reservoir you wait for the frac trucks. During the height of the Eagle Ford Shale boom some operators waited up to 6 months to frac a well. And now it still isn’t ready to produce. Once tested the company now knows how to design their production equipment. Depending on availability of putting the equipment together may add 2 to 6 months to the time line. During this lag time the company can take advantage of the delay by laying the pipeline needed to bring the well to a gathering system. How long does that take? A month or three…and sometimes a year. Two years ago one of my completed NG is S. La. took a year to get the permits and lay across a stretch of swamp land. From prospect generation to flowing well took over 4 years.

Add it up and the entire process from the search for the prospect to NG being sold can be 3 to 5 years. At any time during that process NG prices can fall to such a level as to terminate the entire effort. I have conventional prospects in my inventory that had their birth a number of years ago and won’t be drilled now and perhaps never by my company. I have one prospect in SE Texas that we spent a year and $800,000 leasing and had reached the point where I built the drill site. And then NG prices began to fall. And the further they dropped the more difficult it was to find partners. Eventually we gave up looking. In the next 12 months I’ll likely restore and abandon the drill site as the leases expire. An important take away is that even if we see a significant increase in NG in the next few years one shouldn’t expect a mad rush back into some dry NG trends. The time lag factor also explains why the pubcos have latched on to the shale plays so heavily. Once large acreage positions are acquired wells can be drilled much quicker. Sometimes so quickly companies don’t determine the real economic value of an area until a lot of capex has been expended.

This explains another huge problem the dry shale gas players faced as prices fell. They had hundreds of $millions in leases. So they simply had to wait for prices to increase to justify their development. But time is seldom your friend in the oil patch. Most leases expire in 3 to 5 years after they are taken: don’t start producing in the primary term and the lease automatically expires. And many can’t afford to just wait. In a hot play some land owners require an annual “rental payment” until production begins. In some cases the rental payment might be as high as the original lease bonus. If a company paid $250k for that drill site lease they may have to write that same check every 12 months for as long as production hasn’t begun. Often if a company doesn’t expect to drill some leases in a reasonable amount of time they’ll “drop the acreage”. IOW they give up their drilling rights. Many tens of thousands of east Texas shale leases were dropped before their primary term was reached.

But this creates a new problem for pubcos with large acreage positions on which they’ve booked some PUD (proved undeveloped) reserves. The SEC allows a company to keep such “assets” on the books for a period of time. But if a company drops the acreage they have to take those PUD reserves off the books immediately. I’ve seen many examples of companies keeping PUD’s on their books as long as the SEC rules allowed even when they knew they would never drill those wells. And on occasion make rental payments to retain leases they knew they would never drill: sometimes a more cost effective way to book reserves than with a drill bit. A couple of years ago some folks pointed to ExxonMobil’s acquisition of XTO as proof of the company’s faith in those shale leases. Don’t have access to the exact numbers but I’m fairly certain the majority of those lease have expired or will before XOM drills them. The reason they did the acquisition is because they got proved producing reserves at an acceptable price. XOM faces the same problem as all the Big Oils: replacing/adding proved reserves. Typically such acquisition prices are not based upon the value of the production but based upon how much a company would have to spend to develop the same reserves with a drill bit. Which also assumes there are enough new drilling prospects to even attempt to do this. I’ve worked on acquisitions where there was little future profit but added reserve base that improved stock value. As I’ve mentioned more than once I lost $18 million in net revenue in a similar manner but improved stock price significantly. Got a nice bonus for losing the company’s money. Go figure. LOL. And folks wonder why I’m so skeptical about pubco annual reports/hype.

Which also explains why the shale plays are so hot: without them most the pubcos don’t have a hope of expanding their reserve base…a very important metric Wall Street uses to determine a significant portion of stock value. Recently a major US independent oil that many folks wouldn’t recognize (Energy XXI) made a somewhat shocking statement IMHO: They announced there were not enough undeveloped oil reserves left in the US to sustain their company let alone the entire industry. They are in the process of redirecting their efforts to recovering residual oil from conventional mature offshore GOM fields utilizing horizontal completions. And it’s not just talk: they’ve begun with a $1 billion acquisition of fields and have budgeted $2 billion for drilling. They drilled 3 hz wells so far which have each flowed between 2,000 and 3,000 bopd. Which is identical to a program the Rockman has been putting together for the last 6 months in the onshore theater. And for the same reason: without this project there’s no reason for my owner to keep the company operating. As mentioned before my company isn’t public so we drill strictly for profit and thus have never had an interest in any of the shale plays.

Got a bit long winded but I see a strong paralle between the bust in the dry gas shales and some of the high expectations for the oily shales as far as ever increasing production and the possibility of “independence”. Not an exact 1:1 for sure but some significant similarities IMHO.