Back in July and August of 2014, I published a 3 part set of blog posts which addressed CEO pay. As I described in those posts, the reasons some compensation changes came about in the late 1900’s was to motivate the CEO’s to take risks by changing the risk – reward environment. CEO compensation began to include significant amounts of company stock. This was done to give them an ownership incentive significant enough to take some risk that were needed to see the company continue to do well and make money. In a recent article in the Wall Street Journal the reporter tried to blame the continued low price of crude oil on some board incentives which caused CEO’s of oil companies to keep drilling rates up in the face of an oil production surplus. I thought that the article demonstrated that the reporter had a lack of appreciation of how CEO pay is structured and more importantly, a lack of understanding of the oil industry. The article was headlined, “Why U.S. CEOs Keep On Drilling”.
The first and obvious problem with this is that since the oil price started down near the end of 2014, the active rotary rig count which is compiled weekly by Baker Hughes, Inc and published by Blomberg news service, has dropped from about 1,900 to below 500 today. Most of those were looking for crude oil. That is hardly “keeping on drilling”. It sounds more like cutting drilling back substantially. He blames a keep on drilling mentality on the way oil company executives are compensated. His supporting data is 2014 when the bonuses were at least in part awarded by boards for drilling enough to increase reserves and production rates. For the 10 years before 2014 the oil price has been going up significantly and people had been talking about “peak production”. production rates had maxed out and oil reserves were headed down – forever – the world would be “out of oil”. It took several years, but finally the U. S. production began to increase, and oil became a “growth industry”. No one really expected the increase in production that we have had and when the price started down near the end of 2014 no one, in the financial community at least, expected it to stay down for long. In mid – 2015 we were seeing articles and forecasts from the financial analyst that the oil price would rise in the last half of the year. But drilling started to decrease almost immediately with the price decline. The oil price decline today has made a serious impact on earnings for all production companies and drilling rates have been cut substantially. And why wouldn’t CEOs who have a significant ownership in their companies cut expenses to keep earnings up and the company reasonably healthy?
The problem and the questions are around why production has not been cut substantially. That’s a whole different discussion and requires some knowledge of oil industry economics. There are significant differences between the nature of the petroleum industry and other commodity industries that are poorly understood by most financial analyst as well as some “down stream” industry executives. The first question might be, if you had a producing oil well whose current on-going production cost was $25/barrel and the current price was $30 per barrel so that it has a positive cash flow. And you need cash flow to stay solvent and pay off debt – why would you shut it in? Reducing production and reducing drilling are significantly different decisions.
In the 1970’s I worked for a Fortune 100 energy company that also had other commodity industry involvement. I did industry studies of some of those commodity industries and I also did a computer model of the oil exploration and production business. It was a great educational opportunity. In the boom and bust of the 1970’s and 1980’s there were a lot of company analyst, who were more knowledgeable than some of the outside of the industry people. But even so, if they did not have the direct experience in E&P they were pretty far off on their predictions. In most commodity markets such as intermediate plastics (polyethylene for example) the products are manufactured in a plant to a specific specification. Commodities, by definition, are all alike – no product differentiation – which means that supply/demand/price economics that we learned in college applies pretty directly. My company manufactured intermediate plastics which were a growth industry at the time. There were basically two-year cycles (about the time it took to build a new plant). The price would rise until it was economically attractive to build a new plant. Several companies would build new plants and two years later there would be ample supply and the price would drop so that one could not economically justify a building a new plant until demand rose enough to get the price back up again. The price cycles were maybe 25-30% bottom to top. A 25% increase would justify new construction and inevitably, more than enough plant capacity came on-line in a couple of years to drive the price back down. We also had a copper mining business. The time periods were a little different there, and there was probably less sustained growth than in petrochemicals, but it was pretty similar.
But the oil industry is different for several reasons. First of all, if one builds a plant to produce 100 lbs. of chemicals per day, it will do that for all of its useful life – maybe 20 or 30 years. But an oil well, that when it is first drilled may produce 100 barrels per day. But it will start declining in its rate of production almost immediately. How fast it declines depends primarily on the reservoir characteristics, and all reservoirs are different. In an existing field or producing area, there are some relatively quick and inexpensive things that can be done to keep the rate up – ar least for a while – secondary recovery or infield drilling, etc. In the 1980s – even when the price was relatively low we never stopped drilling. (We had about 4,000+ active rigs in 1981, and about 700 – 800 from the late 80s to the turn of the century. But never zero.) After WWII until 1972, we had a stable oil price because of the state agencies like the Texas Railroad commission took nominations from buyers every month and set mandatory production quotas on every well based on actual demand numbers. This activity was started in the 1920’s justified by oil conservation considerations, so basically we were the “swing producer in the world”. As a producing company we were spending money in that period to maintain our production levels – but mainly in existing fields doing secondary recovery projects. Secondary recovery is a little like de-bottlenecking a production plant. It’s not particularly expensive, but it lets you have more production up to a point. Sooner or later one has to build a new plant. The same as with oil production, there are some things one can do to maintain production in a known area, but sooner or later one has to look for a new area. In a plant one may increase production through de-bottlenecking. In an existing oil field one is not increasing production, one is usually just slowing the decline. Sooner or later, one has to look for a new oil-producing area, and when that happens the game changes.
We’ll look at what that means in Part 2 of this post.