Overall I agree with Mr. Groppe that natural gas is an undervalued commodity at $4 mcf. However, I am going to use some other arguments that correlate with his to drive my point home. Although all of the rig activity seems to be going to the shale plays, I believe there are clearly reasons for why they don’t make up a larger portion of the gas supply. Creative and fast moving Independents have been at the forefront of attempting to retain their leasing through drilling, while at the same time keeping production low. I think this spells for a move higher, but how high will likely depend on the European LNG market, and what price the producers want to start opening the choke at.
I want to delve into Groppe’s observation about the percentage of our rig fleet being thrown into drilling these shale plays. Horizontal rigs are almost strictly going towards drilling unconventional shale gas, so it should be a good indicator as to what type of plays operators are drilling. At the beginning of 2002, right before the ramp up of the Barnett, high spec horizontal rigs accounted for 6% of total drilling activity in America, with shale gas producing next to nothing. As of May 14 the number of horizontal natural gas rigs totaled 605 or approximately 64% of our nation’s fleet. In the Haynesville arena alone, there are now 177 rigs dedicated to the Shale in NW Louisiana and East TX. That’s almost 20% of the entire nation’s fleet dedicated to drilling one basin. So yes, we can clearly see a shift towards the majority of new wells being of the unconventional shale nature. That’s not new info.
The wells that are being drilled though are increasingly being used not primarily to produce gas, but to hold leases. In fact Petrohawk (HK) for their analysts day presentation on Monday went into depth on their lease retention plan. This is something that we are just now starting to see companies address publicly. In fact Aubrey McClendon, Chesapeake’s (CHK) CEO and founder has gone on the record and stated in April that “Up to 50% of all industry drilling for natural gas is tied to the need to retain leases” according to an FBR Capital report. He went on to reiterate his point in an article on Bloomberg stating that CHK would only have about 2/3 of their current rigs running if lease expiration wasn’t a large problem. That’s a lot of rigs and a lot of wells that are being drilled that it seems these companies don’t want to even produce in this pricing environment.
CHK, which is now operating 33 rigs (3.5% of all U.S. nat gas rigs) in the Haynesville shale, clearly has the biggest problem with lease retention. They currently rank 1 or 2 in the four biggest shale plays based off of acreage. They amassed this position at a furious pace, and like other companies who have significant leverage, are scratching their heads as how to accomplish this without discouraging their creditors. Most of this was taken in the leasing bonanza of ‘08 and is looking to expire or have an option to extend at ’08 prices in 2011 and 2012.
What this leads to is decisions not based on geology or where wells will be economic at $4, but as to the smartest way to hold these expensive leases. When you take on this mindset of drilling off your lease schedule instead of which wells will actually make money today, it ups the percentage of wells that eventually will be producing gas at or below conventional levels. Lease retention wells just holding acreage might be adding to our production mix but are not doing near enough to maintain our overall supply for one reason.
Shale wells only have a high EUR’s when they come on at huge IP rates that can counteract the high first year depletion and loss of pressure in the well. When you don’t go after the sweet spots of the play and stray into your Tier 3 areas, you invite wells that don’t even produce as much as a conventionals. One might then ask, why even bother to drill these wells, why not let that lease expire? The main answer to this is that down the road these wells will be cheaper, more efficient, and hugely profitable at the correct price levels, and by drilling one well now on a lease, you can drill 7 down the road for zero finding costs. The companies that initiate the best retention plans will come out of this as the most profitable in the future.
Another trend that is about to be holding back shale’s production numbers are companies utilizing what I’m calling “Supplemental Storage”. We all know about the storage numbers that come out each week and tell us how much gas we injected or withdrew and this is used as an indicator of demand. What I’ve been noticing out here in Northwest Louisiana though is that wells are being drilled but not completed. This means they drill the well down into the formation but they plug it and leave it waiting there until they decide the pricing of the completion and of natural gas is justifiable. This holds the lease, but doesn’t pay out royalties of course. In March Dr. Jonathan Lewis a high level executive at Halliburton (HAL) claimed that
The large backlog of these (drilled but uncompleted) wells as another form of natural gas storage since wells can be completed in the future when demand for the gas is present.
Usually a Haynesville well will eventually cost an operator around 8 million dollars to drill and bring a well online. However, the single most expensive part of this is the completion of the well. CHK estimates its completion costs at around 2.5 million. So when you are dealing with a well that might be marginal at a certain price why would you bring it online at a crappy price when you would be gambling on the well’s performance and possibly losing money? You could use that 2.5 million on another subpar lease retention well that you don’t have to bring online yet either.
Also, wouldn’t you prefer to wait and spend a 1/3 of your capital costs until a point in time when the price will justify bringing the well on? Most of the money for the shale wells are made in the first months when the production rates are huge, so last Winter you saw a flurry of completion activity as people got excited when gas was range trading between $5-6 and there was a ton of heating demand. I think companies saw some of their buddies adopting this tactic last winter and will see a whole lot more of it until we get a pop in prices.
Last piece I want to put out there before I attempt to bring this all together is the LNG picture. Without the Shale Revolution we’d be importing a large quantity of our natural gas in liquid form from Qatar and other overseas countries as we speak. Tudor Pickering and Holt predicted in early 2007, along with the rest of Wall Street, that by 2010 we’d be importing around 6-8 bcf/d of LNG. Most of this was to come from a couple of huge new liquefaction trains that are now capable of producing 4 bcf/d in Qatar and had a final investment decision well before the Barnett Shale was producing anything like it is now. The rest would have come from Trinidad and Tobago, which is now and has been our top importer, Egypt, Norway and Algeria.
Today we are importing 1.5 bcf/d of LNG almost all because of shale gas. Qatar's new LNG has found a home in the Eurozone where the U.K., among others, is trying to bide their time before a Euro shale revolution. LNG is still looking to wash ashore, but with the European market still paying a $2-3 premium we are safe from this supply. When we get a bump into the $6 range, that's when we’ll see the ships being redirected our way.
Producers of natural gas over the past three to four years have made a shift into a reserve base that significantly reduces the risk of dry holes and increases a well’s EUR. With gas prices steadily increasing from 2002 til 2008 came more daring ventures into wildcat drilling and completing of hydraulically fractured slickwater shale wells. At its peak in July of ’08 we saw prices hit $13, then plunge in dramatic fashion to the levels we see today.
The conclusion that I’ve come to is that when you have high prices you can go out and lease up a bunch of acreage and rigs and make money on marginal wells (lease retention wells). When that price starts to dip into the lower thresholds is when producers should be most picky about the wells they drill and about how much production they let off into the market. Producers are being very smart about how they’re using their capital these days, and by drilling wells that maintain leases and aren’t producing that much. At the same time, they are creating “supplemental storage” wells; they are just biding their time for production to sink lower and natural gas prices to soar higher. We are all quick to overlook what prices would be without shale gas. The U.S. should be embracing and thanking the Independents for saving us from another form of imported energy from the Middle East, which would probably be selling around $7 right now.
Yet while they’ve saved us from that, at the same time I believe they got greedy and didn’t develop their resources appropriately and the free markets are attempting to correct that as we speak. They have realized their mistakes of overpaying for acreage and producing as much natural gas as possible and are now in the process of curtailing production on the way to higher prices. We saw an uptick in M/M production in March from today’s EIA monthly report but I think we’ll probably see it plateau out in April and May before we see these low prices force production to be shut in; the rest of summer it should fall off a cliff.
Groppe brings to light some great points but $8 is probably asking for too much and he was probably gunning for headlines more than anything with his doubling call. I expect natural gas to rise by the end of summer and peak out again in January but to the tune of $7 and average around $5.25-5.50 for 2010. However, the biggest wild card, as always, is the Hurricanes, which could or could not send us back to the double digits.
Disclosure: Long CHK