The US shale oil revolution is a classic example of high prices and technological innovation spurring previously unimaginable increases in production. But can the boom continue despite the drop in global prices, driven by further technological development, or are we set to see some unravelling as margins evaporate?

1. OIL
JOHN KINGSTON
Global Director of News
AGAINST PRICES The US shale oil revolution is a
6 insight DECEMBER 2014
Th is time, it’s diff erent.
It’s an old phrase, one that can be
dragged out in all sorts of situations. It’s
also wrong … a lot.
So the question as 2014 comes to a close
is whether the recent precipitous decline
in the price of oil and oil products is just
a short-term decline, soon to be reversed
as the world bounces back to a more
solid $100/b future, or whether this is
the end of a commodity super cycle that
– with a few up and down aberrations –
lifted the price of oil from an infl ation-adjusted
all-time low in early 1999 to
that $100-plus level in the fi rst half of
this year, with an even bigger spike a few
years ago.
It was at a meeting of the US chapter of
the International Association for Energy
Economics in 1999, a few months after
oil had started to climb, that I fi rst heard
the declarations: we are at the start of a
“super cycle” in oil markets, and maybe
broader commodity markets, and it may
run for 15 years.
Do the math: the 15 years is up.
Break points
So let’s assume that cycle is over. If so,
it’s been a wild ride. In early 1999, the
price of oil hit its lowest infl ation-adjusted
level ever and Th e Economist
published a cover story in March that
proclaimed the world was “Drowning In
Oil.” Little did the magazine know the
bottom had already been reached a
month earlier. It climbed steadily to its
all-time high in July 2008, and
plummeted on the back of the Great
Recession. But by February 2009 the
rise had resumed, peaking out earlier
this year.
Precisely when the cycle ended – if it did
– is not necessarily easy to determine. In
a speech given at Platts’ Benposium
conference in June, Peter Tertzakian of
Arc Financial walked through his view of
the way these cycles work. What are key
are “break points,” which he said come
about only once every few generations.
Tertzakian saw a break point in that July
2008 peak, because it accelerated a trend
toward lower demand.
Th at’s not enough to reverse all the
trends contributing to the busting of a
classic example of high prices and
technological innovation spurring
previously unimaginable increases
in production. But can the boom
continue despite the drop in
global prices, driven by further
technological development, or are
we set to see some unravelling as
margins evaporate?

2. OIL
Th e ‘break point’ was not just the
unconventional drilling methods, but the endless
innovation that the industry kept bringing to the
sector, getting more production out of a smaller
number of rigs.
DECEMBER 2014 insight 7
15-year cycle. Th ere are other break
points needed – or more specifi cally,
what Tertzakian called “magic bullets”
– and the biggest one is obvious: the
boom in unconventional drilling.
But it isn’t enough to simply declare that
it’s all related to soaring US and
Canadian production, and that’s that.
Th e type of trends that Tertzakian talks
about – “the industry does not roll over,
it innovates,” Tertzakian said at
Benposium – can be seen in the
Baker Hughes rig count.
According to Baker
Hughes’
worldwide rig count, rigs operating
in the US in October 2011 stood at
a little over 2,000. Th ree years later,
it was a bit more than 1,900, and
production of natural gas and all
petroleum liquids – crude, LPG and
condensate – had surged. Th e “break
point” was not just the
unconventional drilling methods, but
the endless innovation that the
industry kept bringing to the sector,
getting more production
out of a smaller number of rigs.
It wasn’t easy. As Tertzakian noted, “it
took a fi ve-fold increase in the price of
oil to make this change.” Actually, when
we look back on the 1999-2014 oil
super cycle, we see a lot bigger
rise than that. Platts’ Dated
Brent assessment bottomed out at
$9.62-$9.66 on February 9, 1999. When
it hit its 2008 peak on
July 3, 2008, it stood at
$144.21-$144.23, and
had risen by a factor of
almost 15. Even if
you throw out the
craziness leading up
to the July 2008 peak
and its subsequent
breathtaking fall,
and instead look at a
more sustained rise,
Brent peaked out in
May of this year at
about $115, an
increase of about 12
times the 1999 low.
New super cycle
Ed Morse and his
team at Citi have
talked often about the
end of the commodity
super cycle,
declaring it over in
2013. Th e scenario its analysts lay out as
to the causes of these types of swings are
similar to those expressed by Tertzakian:
the price of a commodity (or multiple
commodities) rises as demand increases
due to economic growth; the growth in
demand outstrips the world’s ability to
supply the commodity, and the price
increases; demand is slowed by the
higher prices while capital fl ows into
expanding the supply of the commodity;
and eventually, supply and demand are
brought back into equilibrium, or
maybe a new disequilibrium, with
supply now exceeding demand.
Prices plummet, investment dries
up, demand is spurred by those
new lower prices (just look at
year-on-year fi gures on US auto sales
and see how bigger vehicles are reviving
on the back of cheaper gasoline), and
the ground is set for a new super cycle.
When does the current low price cycle
end then? Tertzakian is holding to his
15-year time frame. And even though
prices did rebound strongly after their
fi nancial crisis-inspired collapse, he still
sees the current weaker cycle as starting
in 2008. So that puts the end of the
current cycle at 2023.
Th at view isn’t unanimous. Earlier this
year, a much talked about story in
Bloomberg Business Markets about
Phibro chief Andy Hall noted that his
fund within Phibro, Astenbeck Capital
Management, had bet heavily on an
eventual increase in prices, with
signifi cant positions taken as far out on
the curve as 2019 (and at levels believed
to be higher than the $80 prevailing in
early November for 2019 prices.) Going
long that far out in a market others are
speaking of as being in the early days of
a 15-year down cycle is a gutsy call.
“
”

3. OIL
8 insight DECEMBER 2014
But the group’s belief appears to be that
the payoff will come down the road …
way down the road.
Astenbeck/Hall’s views on the
sustainability of the shale boom that has
led to current imbalances is shared by
others. Steve Kopits, who runs his own
advisory fi rm, Princeton Energy Advisors,
has spent extensive time studying the cost
of oil services and the ability of
companies drilling for oil to handle those
rising levels. His conclusion? Th ey can’t.
“Unless capital effi ciency improves
dramatically, conventional non-OPEC
oil production is likely to take a
substantial hit, on the order of 1 million
b/d (in 2014),” he wrote in a piece for
Platts’ blog, Th e Barrel. “Nor will the
unwind end in 2014.”
Kopits has identifi ed the factors in a
price-constrained squeeze to work
something like this: the world’s economy
can’t sustain a Brent price signifi cantly
above $110/b, but capital expenditure
costs have been rising at about 10% per
year, a fi gure he gets from what he calls
Barclay’s “indispensable” EP surveys.
Inevitably, there’s a squeeze on
production.
But some recent comments in a UBS
research report on Halliburton show
that the question of high costs vs. slower
drilling can’t be answered nicely and
neatly. In the report, analyst Angie
Sedita said Halliburton had been trying
to get through price increases for
fracking jobs in the US despite the slide
in commodity prices and “no customer
has pushed back” on the increases “nor
come back for any relief.” “Halliburton
remarked that the customers are well
aware that the frack price increases are
for rapidly increasing logistical costs,”
she wrote.
Not only that, but UBS said Halliburton
had “built into its recent round of price
increases the recovery of two more
quarters of cost escalations.” And yet
despite this weak upstream landscape,
Halliburton executives had told UBS that
if WTI oil prices stayed near their current
level of about $80/barrel, the reaction in
cutbacks wouldn’t be immediate; “they
would begin to cut back activity in the
(second half of 2015).”
So if this overview is correct, which side
is right? Th e Ed Morse/Citi/Tertzakian
argument would be that technological
improvements are proceeding at such a
pace that even with higher oil services
costs, and with relatively weak
commodity prices, drilling will continue
for now and supply will continue to rise.
(Citi’s view is that a lower price will only
cut the rate of growth in US production,
but total output will increase.) Th e
Kopits/Hall outlook would probably say
that a rising level of production cannot,
for any sustained period of time,
coincide with lower commodity prices
and rising oil service costs. Put all that
together and an end to the surge in US
output is inevitable.
Tough time
Th e idea that both schools could be right
– we’re headed for a nasty price decline,
followed by a shakeout that tightens
world supplies – can be seen in reading a
statement by energy economist Philip
Verleger in his September monthly report.
Th e much-discussed price war of recent
months, symbolized best by Saudi moves
to not cut supplies and concurrently cut
its own prices relative to international

4. OIL
MAJOR ENERGY COMPANIES’ CASH FROM OPERATIONS AND USES OF CASH
Uses of cash (sum of capital expenditures, dividends, and net share repurchases)
Cash from operations
2010 2011 2012 2013 2014
DECEMBER 2014 insight 9
benchmarks, could lead to a bevy of
consequences that could tighten supplies
in the long run, Verleger wrote. “Shale
fi eld developers in the United States may
reduce capital expenditures ... developers
of high-cost oil sands projects in Canada
might cut expansion and slow operations
... oil production in Venezuela might
collapse as the country’s economic
problems spread to the oil industry ...”
And so on. Th ose sorts of actions might
very well lead to a successful bet by
going long down the price curve into
2019. But it could be a tough time for
investors in the meantime.
One thing that the Kopits/Hall school of
thought often points to is cash fl ow. As the
US Energy Information Administration
pointed out in a study released last
summer, for the year ending March 31,
“cash from operations for 127 major oil
and natural gas companies totaled $568
billion, and major uses of cash totaled
$677 billion.” Th e gap was fi lled with
borrowing and asset sales. A net increase in
borrowing, in particular, “has made up at
least 20% of cash since 2012.”
Th ose sorts of numbers from a presumably
neutral observer like the EIA echo more
passionate statements like those of Arthur
Berman, a long-time shale skeptic. In an
interview earlier this year with the website
ZeroHedge, Berman laid out his
arguments. “Investors are starting to ask
questions, such as where are the earnings
and the free cash fl ow? Shale companies
are spending a lot more than they are
earning, and that has not changed. Th ey
are claiming all sorts of effi ciency gains on
the drilling side that has distracted
inquiring investors for awhile. I was
looking through some investor
presentations from 2007 and 2008 and
the same companies were making the
BILLION $
800
700
600
500
400
same effi ciency claims then as they are
now. Th e problem is that these impressive
gains never show up in the balance sheets.”
Berman’s comments about investor
concern certainly show up in the SP
Small Cap Energy index. A relatively
weak performance didn’t just start this
year with the decline in prices. Total
three-year annualized returns on the
index as of October 31 stood at 4.81%.
For the broader SP 600 index of small
cap companies, that return stood at
almost 20%. (Standard Poor’s Dow
Jones Indices, like Platts, is a unit of
McGraw Hill Financial.)
Th is is a battle that will play out over
several years; maybe 15. But simply
looking into next year, the numbers
clearly favor the short-term bearish
perspective of Citi.
Th ere are many numbers in the monthly
International Energy Agency report, but
the quickest snapshot is the OPEC call.
Th at number is derived by the IEA
estimating global petroleum demand;
subtracting expected non-OPEC supply;
and then subtracting expected OPEC
NGL output. What’s left is the “call,” the
amount of crude OPEC needs to
produce to keep inventories unchanged.
In the group’s October report, the call
for all of 2015 was estimated at 29.3
million b/d; it was less than 29 million
b/d in the fi rst and second quarter.
Meanwhile, OPEC in September
produced 30.6 million b/d and 30.3
million b/d in October, according to
Platts monthly survey, the group’s output
boosted from levels earlier this year by a
turnaround in Libyan production that
had fallen to less than 100,000 b/d
because of the country’s chaos. A rise in
Libyan output to 1 million b/d would
have gotten you very long odds at a
bookie shop and shockingly would have
paid off . (And then in early November,
more trouble dropped Libyan output by
about 400,000 b/d in a matter of days.)
Without changes in output or demand,
that sort of imbalance is going to make
one side of the current debate look very
smart. But it is a long-term play, and it
may take awhile to determine if it really
is diff erent this time.
In 2014 dollars, annuallized values from quarterly reports.
Source: US Energy Information Administration
companies may close the gap
by incurring debt and selling assets