The total Baker Hughes rig count was down 90 for the week, the steepest decline yet seen. The biggest news was that offshore rig count declined by 5 to 49 active rigs, a 10% weekly drop. This number can be very lumpy. The Permian basin lost 25 rigs 454, and I think was the biggest decliner in percentage terms among the major plays. The Barnett gas field lost 25% of its rigs and is now down to 19.
Saturday, January 31, 2015
Inventory levels and contango
From the EIA report this Wednesday, crude inventories are
the highest since they started keeping reliable statistics in the early
1980s. There was an editorial (which I can’t find
now) saying that US inventories are the highest since 1931. In the early 1930s, the East Texas Field was
developed and a glut of oil came on to the market that nearly put the entire oil
industry out of business. Texas asked
the federal government to come in and enforce a production rationing program to
keep prices up and everyone from going out of business. There is a good account of it in the book "The Prize" by Daniel Yergin.
As I mentioned before the crude market is in contango now,
meaning that futures are trading higher than the spot price. Last summer it was in backwardation, meaning
that the futures were below spot.
Contango rewards you for storing oil. There is, and probably will continue to be,
increasing demand for floating storage, as cheap storage fills up. Incidentally if you would like some
excitement, you can trade oil tanker stocks like TNK, DHT, NAT, TNP. But be aware that these are highly leveraged
companies in an incredibly volatile business that has a reputation for
destroying capital that rivals the airline industry.
EIA also has estimates for OECD inventories (above), but the data
quality here is probably worse than their domestic US data. It does show an alarming build however. And now we can also look at production
numbers for the USA:
These production numbers are not as important as whole-world numbers. But the USA is a high cost producer, and one of the countries that the Saudis say must cut production. So far there is little discernible impact of the higher
prices on US production. Surely the rig count drop and
the fast decline rate of shale wells will cause US production declines at some
point, but we are not seeing it yet.
This brings me to the conclusion that this talk that we are now hearing
that crude may have found a floor, really doesn't seem to have any short term
basis. Inventories continue to build,
and there has been no peak in production. Companies
are not selling oil into the spot market because they can store it and sell it
forward at a guaranteed profit. Traders
are doing arbitrage trades where they buy oil, sell it forward and store it on
a tanker. But there are only so many
tankers, and only so much storage.
I would like to call attention to something that happened in
the mid-continent ethane market in 2012.
The production was spiking from all the “wet gas” people were drilling
and ethane storage capacity was limited.
Mont Belvieu is the main ethane hub on the gulf coast, and prices there
dropped by 2/3 in 2 months. In Conway
Kansas, the other listed spot market for ethane, it traded down to about $.01 per gallon. There was simply no place to put it. Because it is only a component of natural gas
production, you cannot turn off the production independently.
Now I don’t believe that anything this dramatic can happen
to oil prices, production would be shut in well before that. But it does highlight that since there is a
fixed amount of storage for oil, and as inventories build and production does
not decline, there could be a further severe sell off in the spot market. The recent ISIS scares in the Kirkuk region
of Iraq could be an opportunity for a short-term bump for people stuck in a position. Although if you think ISIS can capture the
big fields in Shite dominate Basra region, you might be less bearish than I am. That would solve this supply glut in an
instant!
Saturday, January 24, 2015
Rig count and weekly inventory numbers
No signs of an end to the glut from the weekly EIA data for the USA. Gasoline stocks are also on the high side. Distillates (diesel, heating oil, and jet
fuel) are on the low end of the 5 year range, but we have been exporting very
large quantities. I don’t feel competent to infer any major
conclusions from this, but certainly we have not seen anything that suggests we
are approaching the end of the glut.
Rig Count is dropping like its 2009:
We dropped 12 rigs in the Bakken, down to 153. Permian only lost 6, down to 430, and this
represents a deceleration in the rate of decline in that basin vs the past two
weeks. Eagleford lost 4, down to 181,
that is also a deceleration in the rate of decline there. The gas basins held up.
One other observation that I would make is that we have
reached something of a milestone in that ¾ of the drilling rigs on land in the
USA are now horizontal rigs. Vertical
and directional rigs have been dropped more rapidly, increasing the percentage
of horizontal rigs in the total. “Directional
rigs” are basically like vertical rigs but drilled at an angle. They are also called “Slant Drilling”
rigs. Horizontal rigs drill strait down
then make a right turn and drill along a formation for a mile or so, and are a
more modern technology than the other two types.
If we continue to drop at the current rate it will take 3-4 months to get to the 2009 lows.
Davos commentary
There was some
interesting commentary from Davos from the CEOs of the European integrated
oil companies Eni and Total.
"A lot of our projects are long term to have
production in five or six years. And that is a problem. If you are cutting
capex (capital expenditure) drastically now - we can have a lack of production
in four or five years creating a new increased oil price at $200 maybe,"
Descalzi said (Eni CEO).
Of course everyone who produces and sells oil would like OPEC to cut production to prop up prices. Oil majors have been increasing capex and their production has been falling for years now, but the independents and state companies have more than made up for those declines.
From a game theory perspective, the goal of OPEC of providing price stability, may be in conflict with the goal of receiving the highest possible price over the long term.
In other industries, the low cost producers never cut back supply, but
keep producing through downturns for maximum operational efficiency. The global mining firm BHP long said that
their philosophy was to produce from low cost, long life assets, and maintain
production and investment through the entire commodity cycle. (Incidentally they seemingly diverted from
this philosophy when they invested in US shale gas at the top of the cycle). New producers with higher cost supply will
think twice about making an investment if the price can crash from $100 down to $30
at any moment and bankrupt them. Price
volatility can actually be a benefit to the low cost producer because it keeps
down supply, and so props up margins, over the longer term.
The only problem with volatility in most OPEC countries is
that they use their oil revenue to fund massive social spending programs, which
cannot be easily cut back without devastating consequences to their economy. If, like Norway, they instead put oil
revenues into an investment fund, and used the fund to finance their domestic
agenda, they could insulate themselves from the volatility of prices. This may be what the Saudis are doing
now. The only problem, of course, is
that there is a long list of OPEC countries that don’t have a fund like this,
and have little ability to withstand the short term price impacts. Iran, Venezuela, and non-OPEC Russia fall
into this category. Iraq has no savings,
but they have been able to increase production to partially offset the price
declines.
http://www.reuters.com/article/2015/01/21/oil-eni-davos-idUSL6N0V02Z420150121
Sunday, January 18, 2015
The coming improvements in the cost structure of unconventional drilling
The rig count will plummet but production will be resilient
I have mentioned this many times, but I think it is an important point that is not being widely emphasized. The cost structure of the major onshore unconventional plays (Bakken, Eagleford, Permian plus all the less significant areas), will drop dramatically over the course of this year. The so called "breakeven" price for all these basins will decrease very substantially if the oil price stays low. Rig productivity has already been improving every month in every basin for the past several years, but this has mainly been due to improvements in technology and the experience level of operators. There will be several new reasons for efficiency improvements.
Operators will focus on their most economic prospects, rather than drilling for exploration, acreage retention or other more speculative activities. Chesapeake Energy, which had become financially overextended due to the aggressive acreage acquisition strategies of then-CEO Aubrey McClendon, pulled back on capex several years ago after a leadership change. They have shown remarkable improvements in efficiency as they cut capex levels, and I think these changes are illustrative of what is likely to happen industry-wide this year. The reasons for the improvements are various but they all are related to making capital spending choices that emphasize making an economic return on a well instead of prioritizing acreage retention, exploration etc. This leads to increases of multi-well pad-drilling in the core areas of a play, rather than testing out the perifery and drilling single-well pads to hold acreage.
From Cheseapeake Energy Investor Presentation:
After a dramatic cut to the capex budget well costs fell substantially in all regions.
The substantial increases in efficiency that Chesapeake made when they reduced capex will likely be seen industry wide in 2015. But the industry as a whole will have a second advantage in reducing costs that Chesapeake didn't have on its own.
Services costs will decrease due to overcapacity: Schlumberger said on their conference call that they would prefer to "stack equipment" than to give up too much on margins. Maybe, but then they should be prepared to give up market share, and that might disadvantage them for when the market comes back. Service costs are highly elastic, and they should fall dramatically. I don't know enough to be able to make any projections about the extent of this effect, but I would expect it to have a substantial impact on the overall economics of tight oil in the USA.
After the 2008 gas crash we saw rig count come down ~75% and production continue to increase. I don't necessarily think this will happen for oil. If the oil rig count falls by 75% I would expect production to plateau or decline modestly. One of the reasons that gas production was able to grow was that the most efficient gas play, the Marcellus, was just coming on at that time. As rigs left the Barnett, Fayetteville, and Haynesville shale drilling was accelerating in the Marcellus. Each rig there produced more gas than in the earlier plays. Secondly, shale gas drilling is much more efficient from a $/BTU standpoint than tight oil drilling. The best shale gas areas are highly profitable if they can sell their gas at $3/mmbtu, the energy equivalent to selling oil at about $18/bbl. The best tight oil areas are currently marginal at about $40/bbl or a bit under, though this number is likely to decrease.
Where is the consensus and how are my views different? I think the price of oil is likely to decline further from here before recovering. We may be in for a long period of serious volatility, in contrast to the relative stability in the market in the several year period leading up to this summer. It is not possible to make long term projections on price with any accuracy, but I think there is a conventional wisdom that a much higher price is necessary to ensure adequate supply. The "correct" long term price, for instance the 5 year average after supply and demand come back to equilibrium, might be only $60-70/bbl in 2015 dollars. $100 was too high- it created too much new production. It is true that much of today's high-cost oil has a higher break-even than that, but we are in the early innings of tight oil though. There are also big low-cost supplies that could come on the market from Iraq and Iran at some point. Either of these countries have the geological resources to increase production by 4 million b/d if the politics go the right way. Though even in an ideal political climate this would likely take half a decade at the least. While it is fun to guess, I must acknowledge that there is a wide range of possible outcomes, and in the end even a much more informed observer than I can only make an educated guess about how prices will behave over the course of this year.
I have mentioned this many times, but I think it is an important point that is not being widely emphasized. The cost structure of the major onshore unconventional plays (Bakken, Eagleford, Permian plus all the less significant areas), will drop dramatically over the course of this year. The so called "breakeven" price for all these basins will decrease very substantially if the oil price stays low. Rig productivity has already been improving every month in every basin for the past several years, but this has mainly been due to improvements in technology and the experience level of operators. There will be several new reasons for efficiency improvements.
Operators will focus on their most economic prospects, rather than drilling for exploration, acreage retention or other more speculative activities. Chesapeake Energy, which had become financially overextended due to the aggressive acreage acquisition strategies of then-CEO Aubrey McClendon, pulled back on capex several years ago after a leadership change. They have shown remarkable improvements in efficiency as they cut capex levels, and I think these changes are illustrative of what is likely to happen industry-wide this year. The reasons for the improvements are various but they all are related to making capital spending choices that emphasize making an economic return on a well instead of prioritizing acreage retention, exploration etc. This leads to increases of multi-well pad-drilling in the core areas of a play, rather than testing out the perifery and drilling single-well pads to hold acreage.
From Cheseapeake Energy Investor Presentation:
After a dramatic cut to the capex budget well costs fell substantially in all regions.
Services costs will decrease due to overcapacity: Schlumberger said on their conference call that they would prefer to "stack equipment" than to give up too much on margins. Maybe, but then they should be prepared to give up market share, and that might disadvantage them for when the market comes back. Service costs are highly elastic, and they should fall dramatically. I don't know enough to be able to make any projections about the extent of this effect, but I would expect it to have a substantial impact on the overall economics of tight oil in the USA.
After the 2008 gas crash we saw rig count come down ~75% and production continue to increase. I don't necessarily think this will happen for oil. If the oil rig count falls by 75% I would expect production to plateau or decline modestly. One of the reasons that gas production was able to grow was that the most efficient gas play, the Marcellus, was just coming on at that time. As rigs left the Barnett, Fayetteville, and Haynesville shale drilling was accelerating in the Marcellus. Each rig there produced more gas than in the earlier plays. Secondly, shale gas drilling is much more efficient from a $/BTU standpoint than tight oil drilling. The best shale gas areas are highly profitable if they can sell their gas at $3/mmbtu, the energy equivalent to selling oil at about $18/bbl. The best tight oil areas are currently marginal at about $40/bbl or a bit under, though this number is likely to decrease.
Where is the consensus and how are my views different? I think the price of oil is likely to decline further from here before recovering. We may be in for a long period of serious volatility, in contrast to the relative stability in the market in the several year period leading up to this summer. It is not possible to make long term projections on price with any accuracy, but I think there is a conventional wisdom that a much higher price is necessary to ensure adequate supply. The "correct" long term price, for instance the 5 year average after supply and demand come back to equilibrium, might be only $60-70/bbl in 2015 dollars. $100 was too high- it created too much new production. It is true that much of today's high-cost oil has a higher break-even than that, but we are in the early innings of tight oil though. There are also big low-cost supplies that could come on the market from Iraq and Iran at some point. Either of these countries have the geological resources to increase production by 4 million b/d if the politics go the right way. Though even in an ideal political climate this would likely take half a decade at the least. While it is fun to guess, I must acknowledge that there is a wide range of possible outcomes, and in the end even a much more informed observer than I can only make an educated guess about how prices will behave over the course of this year.
Saturday, January 17, 2015
screening for value
I'm starting to compare valuations and get some names ready in case I want to start buying any time soon here. As a reminder, the only E&P stock I own is Whiting at the moment, having sold CHK (July), APA (September), EOG (bought in Sep at 101.50, sold in December 96.50). Other non-E&P energy related stocks which I have owned are CVX and FCX (also sold in September). I also previously mentioned that I own American Airlines, which I bought quite well in September and sold half in December, and I also own CF Industries, a play on durable low-cost North American natural gas.
A year ago I had done a screen comparing the growth rate of production and the enterprise value/EBITDA. EV/EBITDA is the enterprise value, net debt plus market capitalization, divided by the earnings before interest taxes depreciation and amortization. This ratio is a simplification, but it is greatly superior to using the PE ratio for E&P companies, especially for companies where debt is a large part of the valuation.
Today I did another screen but instead of using growth rate I used leverage, as defined by net debt/ebitda. In a contraction like this one it is important to examine the debt situation of the company.
First a few comments on this screen.
1) The gas companies (COG, RRC, EQT, SWN, UPL, AR) appear to be a bit more richly valued than they actually are relative to the oil companies. This is because gas was already low last year, so they can reasonably expect their ebitda to hold up better in 2015. Companies with a lot of "wet gas" such as RRC and AR, will still get hit by lower natural gas liquids prices, which are somewhat connected to oil.
2) This chart might suggest that some of the very highly levered companies are good shorts, such as GDP, SFY, SD. Unfortunately I have missed the boat on these companies. Although their EV/EBITDA may not look particularly low, their equity value has gone down by 80% or more from their 52 week high. Even if I knew for a fact that these companies would go bankrupt a year from now if prices didn't improve, it still wouldn't be a good short. Any rally in oil prices could triple these almost overnight. In fact, anyone who is bullish on oil prices in the near term could buy these if they want some serious leverage.
3) Bakken producers appear over leveraged in general. None of these 4 appear particularly comfortable at about 2-3x net debt/2014 ebitda. Their leverage ratio could increase dramatically next year if we see no improvement in oil prices. On the other hand, some of these companies are trading at under $10 per barrel of proved reserves. Recent offshore projects, like the Hes one approved several months ago, have $20 capex per bbl of "recoverable resource). These companies may be prime candidates for the majors or large-cap E&Ps if things stay ugly.
4) Permian valuations still seem high to me, but I've been saying this for a while and the gap has not closed.
5) The valuation gap between the smaller and larger companies has closed (smaller companies used to be valued more highly), but the large caps still seem to be a better bet to me. Although they were growing more slowly, this may turn into an advantage, since the smaller companies will see much bigger declines if they stop drilling- more on this later.
5) Some of the lower leverage, low valuation midcap companies like QEP and SM might deserve a look on the long side. They have seen huge declines but don't have much debt.
1/16/14 rig count commentary
The Baker Hughes weekly rig count came out on Friday, and we are seeing the decrease in drilling activity continuing to accelerate. 74 rigs dropped, or 4.4% of all US active land rigs. This is a slight acceleration in the rate of decline since last week, and at the current pace, we could drop 25% of active rigs in the next month. 44 of the 74 were in Texas, including 15 in the Permian (487 rigs) and 12 in Eagleford (185 rigs). The major oil basins are all about 12-17% off their early October peaks. The Granite Wash (43 rigs) is 33% off the early october number, and has been the biggest decliner. The Utica (49 rigs) and Barnett (25 rigs) are the only significant plays that haven't seen a decline yet.
I'm going to keep watching this since for the next weeks. I didn't used to comment on it because there was too little change from one week to the next to be particularly interesting.
I'm going to keep watching this since for the next weeks. I didn't used to comment on it because there was too little change from one week to the next to be particularly interesting.
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