Oil Industry Econ – What Investors need to know – Part 2

For oil industry drilling and production project costs, the front end costs are substantial.  The differential can vary sharply depending on the depth of the well and the reservoir characteristics.  In the middle east – Saudi Arabia for example – with porous oil sand reservoirs with good reservoir pressures, the wells flow naturally at high flow rates without being pumped.  The cost in the 1970’s was estimated to be well less than a $ per barrel.  At the same time in the North Sea, where the environment was less friendly and there were people on platforms and pumping costs to get the crude to shore, the costs were closer to $10 per barrel.  In the U.S. it was, in most cases, in between.  In today’s environment, for tight shale reservoirs the costs are considerably higher.  One company leader with substantial shale production said their cost for continuing production in a drilled and completed well was $20-24 per barrel. But he also said that they had viable economic drilling returns in the better part of existing fields at $40 per barrel.  Others operating in lesser productive parts of those fields would have higher production costs, and for them, it probably would not be economic to drill at $40 per barrel.  A few years ago, when oil prices were still headed up at about $75 or $80 per barrel, a friend told me that his small independent oil company could continue drilling the prospects they had at prices in the mid $60’s.

The variance in costs between different oil production opportunities is un-heard of in other commodity industries that I have had some experience with.  The price needed to justify continued production versus that needed to justify drilling may be a multiplication  factor of two or more.  And the difference between the prices that make it economic to drill a well may be more than that.  There is also a signficant difference between doing projects in new field “wild cat” projects as opposed to development drilling in a known reservoir.  I don’t have quite the same access to data today as I had 20 years ago,  but in the 1970’s new field “wild cat” wells had only a 10% chance of being productive whereas, development wells in known reservoirs had an 80-90% chance of not being “dry holes”.   With improvements in geological and geophysical tools that has probably improved today, but I suspect there is still a substantial difference. There is also probably a difference in the tight shale plays, because I think we have better information on where those are.  The problem has been having the technology to produce them.  But they are likely more expensive to produce than conventional reservoirs and reportedly decline at a faster rate.

In the late 1990’s I was doing classes for several different companies on the Basics of the Natural Gas Industry. (I also put together one for a major company on the Basics of the Petroleum Industry.)  At the time, it was fairly apparent in looking at government published data that at the then current drilling rates we were going to have a shortage of Natural Gas at some point in the near future.  But no one knew exactly when.  It took longer than a lot of people predicted, but it happened early in this Century.  (In 1978 the U.S, government passed energy legislation that outlawed using natural gas to generate electricity because we were going to be out of gas by  1985. It turned out that was not the case but it seemed we might be facing another shortage 20 years later.)  Oil and gas-producing companies reduced staff through the 1980’s and with the relative stability of production through the 1990s little of these resources were added back.  Then after the turn of the century,  natural gas availability became an issue and in 2001 the natural gas price started to rise.  By 2007 -2008 there were almost 2,000 rigs running, most of which were looking for natural gas.  Then oil became the problem.  Many “experts” were saying that we had reach the point of “peak production in oil”.  As natural gas got back to abundant supply and the price started dropping, the number of active rigs dropped momentarily in 2009.  But by 2012 were back to 2,000 +.   The difference before and after 2009 was in how much drilling was looking for natural gas and how much was looking for oil.  The price of gas had peaked at about $10/mmbtu at the end of the decade and then dropped to around $3 for several years.In the meantime oil prices had started up from the price of around $20-25/ barrel where they had been for a long time.

I think what happens is that with ample supply and lower oil and gas prices, the projects are to maintain or increase production from existing fields and known areas.  But there are limits to this, at some point one has to start to look for new fields in new areas.  My E&P model from the early 70’s was based on new-field wild cats in regions that had no or little explorations.  One needed to do geological and geophysical work, acquire the rights to drill, then drill one or more exploration wells and then drill development wells.  In some cases some infrastructure (e.g. pipelines, etc.) was needed to get the oil or gas to market.  The total period from start to full production was about seven years.  That was assuming availability of equipment (rigs) and manpower (geologists, engineers and roughnecks, et al.).  In 2000 – after 20 years of modest activity – there was a need for more of all of these resources.  Daily rig rates and costs of other equipment went up with increased demand, so costs went up.  But probably the most important thing for investors is appreciating the time lags.  When things go in one direction for longer than we expect, we tend to think they will go on that way forever.  For other commodities, two years might be the norm, for oil and gas it may be more than twice that long.  For most commodities, prices go higher than they need to go to justify new production.  But in a couple of years they won’t go that much before production catches up.  For oil and gas it may be 3 times that long or more so the difference between the price needed and how high it eventually goes before supply increases is signficantly more.

In the 1970’s my seven-year tome period held up fairly well.   The arab embargo which caused the price rise started at the end of 1972, and we found out we had hit the max production capacity in this country a few months after that in 1973.   By 1980, non OPEC production had risen enough to get OPEC to agree to production cuts in order to hold the price of oil.  By 1983 the only OPEC country to cut production – Saudi Arabia – had cut their production rate almost in half.   It was at that point that they began to feel enough pain to decide to open up their wells and drive the price down enough to get others to cut production.  The price went from about $35/barrel to less than $10 or enough to put enough people under their ongoing production costs to start shutting in wells.  At that point they adjusted their production enough to let the price get back up to around $20/barrel.  Enough for some if us to think that they were picking a price level that would allow some drilling without feeding another drilling boom. The price stayed in the low $20’s for about the next 15 years.  The Saudi’s had become the swing producer and the Texas Rail Road Commission, (et. al.) had stopped  taking monthly nominations each month and setting monthly per well allowables.

What all that history might say about today’s will be the subject of part 3 or this post.


About tjc13

BE - Chem Engineering, Vanderbilt Univ, MBA, University of Tulsa - Worked for an energy and chemical company for many years and then started a management consulting business working for both for-profit and not-for-profit organizations.
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