Chesapeake, another beat and raise by a large independent + a brief history

CHK came in at $.59 per share, vs analyst expectation of .48.    Adjusted EBITDA was up 34% yoy, and most amazingly capex at only $850mm was far below cash flow from operations of $1.29b.    Production was more or less flat though they tout that it was up 11% excluding divestitures.   Just a few years ago these guys were spending $14b a year in capex! 

I own some Chesapeake shares because I believe they can turn around and make money through drilling rather than as a real-estate speculator, their previous business model.  I also know how much the investment community hates this company  because of past misdeeds (mainly associated with their former CEO).

I’m going to do additional posts on Chesapeake that go into more detail, but by way of an introduction… they were founded by Aubrey McClendon, a landman.  He was an early adopter of the horizontal drilling and hydraulic fracturing and participated in the early Barnett shale rush around Ft. Worth Texas, the first significant US shale gas play.  Mitchell Energy is credited with making the discovery, and he sold out to Devon Energy in 2002.  Other early players included Chesapeake, XTO, EOG, Range Resources, and Encana. 

Chesapeake early on realized that there were other large plays out there, and set out to lease up huge swaths of territory.  They would send out a small army of landmen to sign leases with all the individual landowners.  In many cases the landsmen would be working for private companies, and may not even know they were working with Chesapeake.  At some points (according to rumor) they employed as many as 10,000 landmen at a given time, mostly indirectly.  Step two was to announce a position in a new play and trump up some well results.  Step three was to sell a share in that interest to a larger company like Statoil, CNOOC, or Total.  Ideally they could fully cover exploration and leasing costs by selling that fractional interest in the play to the other company.  Much of the money was usually in the form of a drilling carry, which means that the other company pays your share of the capex for new wells until that carry runs out.  Chesapeake liked this arrangement because usually the first wells were the least efficient and most expensive, partly because they had to drill lots of lone wells to hold all the leased land by production. 

An oil or gas lease typically involves two types of payment, a bonus and a royalty.  The bonus is a flat fee per acre paid to the landowner.   $1,000 per acre wouldn’t be unusual.  Then the landowner also gets a royalty, which is a negotiated percentage of revenue from the well.  12.5% is sort of the baseline, but 15 or 17% isn’t unusual.  Production that an oil company reports on their financial statements is net of that royalty in the USA (but not Canada).  Terms are usually a closely guarded secret.  After securing the lease and paying the bonus, a company has to start producing from the land within a certain window (2 years in some areas, as much as 5 in others) or they lose the lease.  In some cases the company has the option to repay the bonus to start the timer again.  Once they start producing and paying royalty, the lease is considered “held by production” or HBP.  In most cases the land is “unitized” so that all the land in a square mile is considered one unit.  The landowners from that unit will share revenue equally according to the percentage of land owned by each individual, regardless of whose land the well is actually under.  So under that arrangement, if a company had leased up exactly 100 square miles of contiguous acreage, they would have to drill at least 100 producing wells over that area to hold all the land by production.

Now this is much less efficient than “pad drilling” where a single plot of land has a number of wells on it, each going out in a different direction underground.  Say a company decided to use 60 acre spacing.  A unit has 640 acres.  In some cases 10 wells might be drilled all right next to each other on one plot of land, but underground they are spaced out so as to drain the whole unit.  This is much more efficient because only one well site is prepared, and all the roads and gas gathering infrastructure can be shared easily between wells.  So when a company first leases land, it must drill inefficiently: a well here, then a well over there etc because they have to HBP the land.  But much later it is doing “infill drilling” or “pad drilling” which is more cost efficient.

Chesapeake never really got to infill drilling until recently.  They would lease up huge swaths, sell to a major, and use the cash to drill and hold land, or go and find more land.  The scale of the operation was rather incredible.  In some years they spent $6b and more leasing up land.  They also were running a fleet of 180+ land rigs at times, or 1/10^th of all US land rigs, and a much higher percentage of all horizontal drilling rigs.  The only thing that went wrong was that gas prices crashed in 2008 and is only now showing signs of recovering.  They’ve belatedly followed EOG's lead to diversify into unconventional oil drilling, and they've sold one thing after another during the past few years, to try to pay back some of their $12.5b in long term debt.  Now that they are trying to act like a normal company that makes money by drilling for oil and gas, I do think they’ll ultimately be successful at turning the corner, especially given the recent rise in gas prices.