There are a variety of different ways of looking at the cost
and productivity of the various shale regions.
This is an important topic, especially because I often read people
saying that much of the shale gas or tight oil is not actually economic based
on the fact that the companies are collectively free cash flow negative. I’ve already expressed my reservations about
the metric of free cash flow in the context of E&P companies, as it is
conventionally measured. (Go to cash
flow statement, take cash from operations, subtract capital expenditures). I argue that sold assets should be added back
in, so really it is more useful to take cash from operations and subtract cash
from investments in total. If we do
this, the 26 companies that are being studied here had cash from operations
that exceeded investments by 9% in 2013, after running a deficit for the previous
two years. They also grew “value
adjusted” production (take barrel of oil equivalent production and discount gas
by 2/3 and ngls by ½) by about 7% last year. All this implies that returns are improving. I think that this is the case, and that there are a number of potential reasons for it.
Reasons returns may be improving for domestic E&Ps:
- 1) Moving to pad drilling. In the past most wells were drilled on single well pads to “hold by production” (HBP) all the lease areas. More on this later, but the gist of it is that oil and gas leases force companies to drill within a certain time span or else they lose the lease. After leasing up huge swaths of land, they had to go on a very inefficient campaign to drill a well in every 640 acre drilling unit to hold all that land. Most companies are now moving more and more to drilling many wells on a single well pad, which is far more efficient. Recent Chesepeake Energy presentations have discussed this quite a bit.
- 2) More wells are being drilled for the purpose of making money rather than testing the boundaries of a play or searching for new plays. This is similar to the first point, but you are starting to get some companies saying that the big unconventional plays have been found. Whether or not this is true, it is clear that the companies are generally more focused on drilling profitable wells rather than finding more resources. I believe this will lead to better returns.
- 3) Better well results due to improved well design. As companies spend more time in certain plays, they are able to learn better how to drill in those areas. Last year changes in well design that Whiting made in the Bakken has led to wells flowing about 60% more oil over the period studied.
- 4) A decrease in infrastructure development costs as plays mature.
- 5) A decrease in leasehold acquisition costs (it’s all been leased up).
- 6) Better pricing as infrastructure is built out.
- 7) Many companies drilled uneconomic gas wells in the 2006-2009 period based on unrealistically high expectations of future gas prices. We aren’t seeing this anymore.
On the other hand, it is also worth noting that a few of the
larger companies are milking foreign assets for cash flow while investing in the
US, so if foreign assets were excluded there would be somewhat less of a cash
flow surplus. Apache’s Egyptian assets
are a good example of this. It’s been a
free cash flow gusher for years now. It’s
also important to point out that these companies are all EXTREMELY levered to
the price of oil. Oil majors like Exxon
and Chevron are much less levered to the price of oil because they also make
money from refining, but more importantly, much of their production is in low
cost overseas regions, where the profit margin is very high, although they only
get a small slice of the profit. A
decrease of oil price in the USA by $20 per barrel would be devastating for
many E&P companies in the long term, but it only would crimp profits a bit
for the oil majors. The converse of this
is that if the price goes up by $20, it will be much more important for the
E&Ps than for the majors.
But of the various
plays, which is the most efficient? For
gas, I think its very clear that the Marcellus has the best rock, and best IRRs
at current prices, but it remains very limited by infrastructure, I’ll get more
into the other gas plays later, but companies considering investing in the
Barnett, Fayetteville, or Haynesville need to study the infrastructure plans
surrounding the Marcellus. The only
thing holding the price of gas up is
that the area where it’s cheapest to produce is constrained from expanding by
current infrastructure.
For unconventional oil,
where the vast majority of investment is currently going, there are three main
plays that we will focus on and I’m going to look at two different ways to
compare how productive these three regions are.
One way to compare is to look at the reports of the biggest
unconventional oil producer, EOG, who is active in all three plays, but
unfortunately they are no longer putting out internal rates of returns for the
various plays. They have said repeatedly
that Eagleford has the best returns, Bakken next, and Permian is a distant
third. I will try to compare the rates
of returns based on company claims, but the different companies use a variety
of different IRR metrics in their presentations, usually with limited
explanation of how they are calculated. There
are also presumably different methods for estimating revenue from the wells, and
there is certainly the possibility of excessive optimism when companies create
their investor presentations.
Then there is a very interesting monthly report from EIA.gov
(department of energy). They come out
with a monthly drilling productivity report for the Bakken, Permian, Eagleford,
and Marcellus.
This is a fascinating report. Basically they say that there are 500 b/d of
new production each month per rig. If we
take this times 180 rigs, we get about 90,000 b/d of new production, but then
there are declines of 69,000 b/d (a rather astonishing 6.9%) on existing wells,
yielding a net increase of 21,000 b/d.
At some point the rigs will only be able to maintain production, and no
longer grow it, but it is not yet clear where that production peak will be, it
is certainly not in sight yet.
The eagleford is growing at a 50% faster rate and is already
much higher in production than the Bakken, despite only getting going in 2010
vs 2008 or so in the Bakken. But there
are a number of other things to think of when comparing these two charts. For one the Eagleford has 50% more rigs, so
growing faster doesn’t seem as impressive.
Secondly, I think NGLs are being counted as “oil” here, where as in the Bakken
it is only black oil. Third, the
eagleford is producing almost 7 bcf/d, which is 1,170 mboe per day. So the Eagleford produces almost as much
energy equivalent of gas as liquids, while Bakken produces negligible gas at 1
bcfd. If we give the 2/3 haircut to get
rough value equivalence, the Eagleford gas is worth another 390 mbbl/d of oil
in value equivalence, meaning the Eagleford is already about 1.8 mmbbl/d in
total, vs only 1.0mmbbl/d for Bakken despite bakken having maybe 40% more time
to get there. Learning from Bakken definitely
carried over to Eagleford though, which probably helped it get a faster
start. Being so near the gulf coast also
helped with infrastructure constraint issues compared to the Bakken. There are so many puts and takes there, but
my general sense is that Eagleford is more economic than Bakken by some modest margin.
Now Permian is another animal altogether.
Permian is growing at only 13 mbbl/d month over month vs 21 for bakken and 31
for eagleford. This is despite the
incredible 500 rigs working there. Total
oil production is about the same as the Eagleford currently (though not for
long), and gas production is less at 5 bcfd.
I think it is clear that the Permian is less economic than either of the
other two, but one thing should be mentioned.
Many of the rigs in the Permian are vertical rigs, which cost less to
operate than a horizontal rig, so the per-rig new oil production rate of 100
bbl/d vs 500 bbl/d for eagleford and bakken isn’t quite as bad as it may at
first seem. Fracs are also smaller and
fewer stages for these vertical wells, cutting pressure pumping costs for these
companies. But even so, the difference
of 500 bbl/d of new oil per rig vs 100 bbl/d is pretty big. All this begs the question, why are the
Permian focused companies trading at such a premium to the Bakken names on
either a daily production basis or an EV/EBITDA basis? This is a question that I do not have an
answer for.
No comments:
Post a Comment