U.S. Research
Published by Raymond James & Associates
Energy
January 10, 2011
Industry Brief
J. Marshall Adkins, (713) 789-3551, [email protected]
Collin Gerry, (713) 278-5275, [email protected]
Michael Noll, Res. Assoc., (713) 789-3551, [email protected]
Energy: Industry Overview _____________________________________________________________________________________
We Don`t Hear Her Singing, the Pressure Pumping Party Ain’t Over Yet
1) We remain bullish on pressure pumping fundamentals (expect increased stock volatility). Pressure pumping stocks have already
had a late start out of the gate in 2011. This underperformance is probably due to anxious bulge bracket sell-siders essentially
shouting fire in a crowded theatre. We think these fear mongers are missing several important fundamental issues that will be
highlighted below. While we must acknowledge the negative trading psychology that will partially drive the pressure pumping
stocks over the next year, we also think bullish fundamentals still matter. Based on our pressure pumping supply/demand model
(published below), we believe that the pressure pumping market will stay strong (or modestly undersupplied) into early 2012.
Remember, less tight does not mean oversupplied. This should lead to strong pricing, margins, and upside to current estimate for
at least the next two quarters. That means there is still some meat left on the bone for the stocks to appreciate in this
environment.
2) The market is missing the impact of higher equipment attrition rates. How long would your grandmother’s Cadillac last if Dale
Earnhardt Jr. took it for a couple hundred laps around Talladega without a pit stop? That is what the industry is doing to pressure
pumping equipment today. We believe equipment attrition rates are set to explode (no pun intended) in 2011 and 2012. This is
the single biggest factor the market is not talking about and does not fully understand. We believe annual attrition rates are set
to climb from the mid-single digits to 20+% by 2012, which could equate to over two million horsepower per year being removed
from the market.
3) We also think the market is confused about total pressure pumping horsepower capacity. We estimate that there is roughly 10
million horsepower in the market today. This is up at least four-fold from a decade ago. We believe that we will add 3.6 million
gross horsepower, which will be offset by one million horsepower attrition for net addition of 2.6 million (or roughly 26%)
horsepower in 2011. In 2012, we are estimating gross additions of 4.3 million horsepower offset by 2.3 million attrition for a net
addition of two million horsepower (or about 16%). The summation is that we believe total horsepower supply will grow from 9.6
million to 12 million to 14 million over the next two years.
4) Does the market really grasp the difference between a demand-driven downcycle and a supply-driven downcycle? While the
difference may be subtle, it is relevant. The past two most recent cyclical pumping stock sell-offs were initiated by fears of a
commodity-driven activity collapse. In other words a demand collapse was the problem. At this point in time, such a demand
collapse does not appear imminent. Accordingly, we think the supply-driven rollover in industry margins that is headed our way
will likely be much more gradual in nature than recent downturns.
5) Valuations are not expensive. Despite an approximately 50% run in stock prices since September 2010, most North American
pressure pumping names trade at historically attractive valuations. On average, the group currently trades at approximately 15x
2011 EPS and 12x 2012 EPS, which is a discount to the historical (last two decades) average of 20x but is in-line with historic
valuation levels at this point in the cycle. Thus, we do not believe multiple expansion will be the primary driver of stock
performance, but rather rising EPS estimates.
6) What are our favorite names? Our favorite pressure pumper remains Halliburton (HAL/$38.45/Strong Buy), as its vertical
integration should prove to be large competitive advantage even as the pressure pumping cycle in North America begins to roll.
We also favor Patterson-UTI Energy (PTEN/$19.99/Strong Buy) and Complete Production Services (CPX/$26.34/Strong Buy), which
should benefit from strong leverage to the pressure pumping market. In addition, other companies worth considering in the
pressure pumping realm include Nabors Industries (NBR/$22.76/Strong Buy), Baker Hughes (BHI/$56.60/Outperform), Basic Energy
Services (BAS/$14.62/Market Perform), RPC Inc. (RES/$16.77/Not Covered), and Carbo Ceramics (CRR/$99.31/Not Covered).
Please read domestic and foreign disclosure/risk information beginning on page 14 and Analyst Certification on page 14.
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Over the past six months, pressure pumping has been one of the hottest spaces in the entire oilfield. For tenured energy investors,
this can be a scary prospect. Why? Pressure pumping has historically been one of the more cyclical sectors within the oilfield.
When activity strengthens and industry capacity becomes constrained, it quickly leads to sharply higher utilization, pricing, and
margins. This prompts significant investment in new pumping capacity. Since it is not that hard to add pumping capacity, pressure
pumpers ultimately add enough capacity to bring margins (and pricing) down sufficiently to discourage the newbuild process. If this
is coupled with an unexpected drilling slowdown (as in 2008), then it could be a disaster for those service companies levered to
pressure pumping.
Since many investors have seen this movie before, buy-siders
typically rush to the exits before they get crushed by the
stampede of sell-side analysts calling an end to the pressure
pumping cycle. That is where the pressure pumping investing
psychology stands today. Fundamentally, pressure pumping is
enjoying its third straight quarter of strong and rising
profitability, while investors are beginning to head for the exits
to beat the crowd out of the theatre that is sure to catch fire.
Many of our counterparts are already yelling “fire.” The easy
call here is to pull the trigger now, get out, and ask questions
later. The harder call is to understand how the industry has
changed over the past five years and apply those nuances to
your investment philosophy.
2010 Stock Price Performance
1.7
1.6
1.5
1.4
1.3
1.2
1.1
1.0
0.9
0.8
0.7
S&P 500
OSX
Pressure Pumpers
Source: Thomson Reuters
Note: "Pressure Pumpers" includes: HAL, SLB, BHI, CPX, NBR, PTEN, and RES
In this piece we will shed more light on how we think the pressure pumping industry has changed and how that might affect the
longevity of this pressure pumping upcycle. The question is not will the industry overbuild and margins fall? That is a given. The
better questions are when will the industry overbuild, how rapidly will margins fall, and how long can we own these stocks? Over
the past few months, we have met and spoken with numerous industry participants from pressure pumping companies and
manufacturing companies in an effort to answer these questions. We have assembled a detailed model that attempts to capture
what we have learned and will help to forecast the timing and magnitude of industry profitability trends. Based on this model, we
continue to believe that the pressure pumping market can absorb new capacity and see improving profits and earnings into 2012.
In other words, the calls for a peak in the pressure pumping earnings cycle in early 2011 are likely premature. That said, the stock
market psychology will likely force the pumping service-levered companies to peak well before earnings. Even though earnings
should grow into 2012, the pumping stocks will likely see increased volatility over the next few months and may lose steam in
mid-2011 as the fear mongers pressure the market. As we will detail further in this piece, there are a number of factors supporting
our belief in stronger-for-longer fundamentals. On the supply side, the industry is clearly adding a lot of fracturing horsepower.
Offsetting that, attrition rates are meaningfully higher than just a few years ago (a point underappreciated by those calling for an
end to the cycle). On the demand side, we believe that horizontal rig activity will continue to climb in 2011 as oily frac-intensive
horizontal plays continue to more than offset deteriorating gassy horizontal drilling and overall fracturing activity remains relatively
strong in a weak gas price environment. In this piece we will attempt to quantify the key pressure pumping supply and demand
trends and ultimately forecast the timing of meaningful market and stock price softening.
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Pressure Pumping – What Is It?
After a well is drilled, it must be completed. Completion is the
process of placing and cementing production tubing in the well,
perforating the well, and stimulating the well to allow for a freeflowing oil and/or gas production stream. While pressure pumping
is used for various services (cementing, acidizing, etc.), it is the frac
stimulation component that is currently dominating the industry.
Fracturing is done by pumping specialized (and generally benign)
fluids at extreme pressure into the wellbore. Suspended in these
fluids are tiny grains of sand or proppant. The fluid acts as a wedge
as the pressure drives it through the formation, creating fractures.
Once created, the fractures are propped open with sand or ceramic
beads. The end result is a more productive free-flowing pay zone
that has more pathways to bring oil and gas into the wellbore. The
first jobs were pumped 65 years ago using a few hundred horsepower
cement pumps (less than 1,000 hp total) and a few thousand pounds
of river sand and took less than an hour to pump. Today, frac jobs
have upwards of 50,000 hp on location pumping millions of pounds
of specialized proppant, millions of gallons of specialized fluids, and
can take a week to pump.
Source: Hydraulic Fracturing Facts.
Today’s Frac Jobs Are Not Your Granddaddy’s, Daddy’s, or Even Big Brother’s Frac Job
While the goal remains the same, today’s frac jobs differ drastically from the early days of pressure pumping. Heck, they hardly
resemble those from just two or three years ago. The difference? Size! The emergence of horizontal drilling with multi-stage fracs
has completely changed the game for hydraulic fracturing in North America. Today, we are pumping many more stages per well
(and more per rig), at higher pressures, higher pump rates, and with more proppant per well. That means the industry needs more
horsepower per active drilling rig and that horsepower is pumping more hours per year and lasting fewer hours per truck than ever
in history. It also means that maintenance is already exploding and equipment attrition is poised to explode in the coming years.
Since this is a very new phenomenon, there are no clear-cut answers to many of the industry’s current and future supply and
demand trends. In this piece we will attempt to explore and quantify as best we can each of the key pressure pumping
supply/demand issues. We should warn you up front that after many hours of interviews with industry participants, there is no
consensus industry opinion of many of the issues facing the pressure pumping industry today. That said, it is our job to forecast and
predict the direction of the industry for investors, so here it goes.
Recent Demand for Pumping Horsepower Has Grown Exponentially Faster Than the Rig Count
Over the past five years, the average annual U.S. rig count has fallen about 5% while the demand for fracturing horsepower has
more than doubled. Going forward, we expect that the North American rig count will post modest growth, but we expect pressure
pumping demand to increase another approximately 20% in 2011 before leveling out at a three-year average growth rate of 510% after 2011. A summary of our estimated historical frac horsepower demand and forecasted future demand is shown below.
Frac Horsepower Demand
NAM Rig Count
14,000,000
6000
12,000,000
5000
Forecast
10,000,000
Horsepower
5000
NAM HP Demand Per Rig
7000
North American Rig Count
6000
8,000,000
4000
4000
3000
3000
2000
2000
2,000,000
1000
1000
0
1Q03
3Q03
1Q04
3Q04
1Q05
3Q05
1Q06
3Q06
1Q07
3Q07
1Q08
3Q08
1Q09
3Q09
1Q10
3Q10
1Q11E
3Q11E
1Q12E
3Q12E
1Q13E
3Q13E
1Q14E
3Q14E
1Q15E
3Q15E
Horsepower Demand Per North American Rig
Frac Intensity Growth
7000
Source: Baker Hughes, RJ Est.
Forecast
6,000,000
4,000,000
Source: Industry Sources, RJ Est.
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The primary factor driving the rapid increase in pressure pumping demand has been the growth in the horizontal rig count. Over the
past few years, pressure pumping intensity per horizontal well has been at least 5x that of a “standard” vertical well. Moving
forward, we expect that the horizontal rig count will continue to increase as a percentage of the total rig count and the pumping
intensity per well will continue to increase. In percentage terms, horizontal drilling should grow from approximately 55% of the
total today to 65% by the end of 2011. Of note, we are modeling the overall North American rig count to increase at a CAGR of
approximately 5% from today though 2013 (resulting in 12% average annual growth in the horizontal rig count). More specifically,
we believe weak natural gas economics will drive drillers out of the horizontal dry gas plays (Haynesville, Fayetteville, Woodford,
etc.) and into more liquid-rich basins (Bakken, Niobrara, Bone Spring, and Permian). This shift toward oil-based drilling should
further add to frac demand since horizontal oil wells tend to use more frac stages per well than horizontal gas wells.
North American Rig Count
2000
1,500
1500
1,000
1000
500
0
Source: Baker Hughes, RJ Est.
Forecast
500
0
70%
60%
50%
40%
Forecast
30%
20%
10%
0%
1Q03
3Q03
1Q04
3Q04
1Q05
3Q05
1Q06
3Q06
1Q07
3Q07
1Q08
3Q08
1Q09
3Q09
1Q10
3Q10
1Q11E
3Q11E
1Q12E
3Q12E
1Q13E
3Q13E
Rig Count
2,000
2500
Vertical
Horizontal
% Horizontal Rig Count
2,500
% Horizontal Continues to Increase
Source: Baker Hughes, RJ Est.
Compounding the growth in the horizontal rig count will be the push to drill wells with longer horizontal sections (“laterals”) and
more frac stages per well. In an attempt to increase reservoir contact, operators are now drilling an average of 5,000-foot laterals in
the shale plays, which is almost double that of a few years ago. Likewise, the oil plays are averaging upward of 30 stages per well,
while the gassy horizontals are around a dozen per well. Both of these numbers are meaningfully higher than just a few years ago.
As you can discern from the discussion above, there are many rapidly changing variables that will ultimately determine the demand
for pressure pumping horsepower over the coming years. Accordingly, we have developed a proprietary frac horsepower
supply/demand model that allows us to forecast upcoming trends. On the demand side, we factor in several variables to get to our
ultimate frac demand forecast. A discussion of these key variables and our logic follows. (Please note that the following details
apply to the U.S. and exclude our Canadian estimates that are incorporated into the model.)
•
•
•
•
•
•
Average annual 2011 U.S. rig count up nearly 14%. While this may seem high, we are assuming that total U.S. rigs increase
only modestly (about 50 rigs or 3%) from where we are today. This assumes a roughly 100 gas rig decline from recent levels
paired with roughly a 150 oil rig increase from here.
The average annual horizontal rig count is expected to increase nearly 30% in 2011 from 813 rigs to over 1,050 rigs.
Measured another way, the percent of rigs drilling horizontal increases from an average of 53% in 2010 to 60% in 2011.
Average days required to drill a horizontal well should continue to fall. A conservative guess is that the average days
needed to drill a horizontal well falls from 25 days to 24 days. For reference this is down from 28 days five years ago. Given
the shift out of the Haynesville and into shallower areas, it will likely fall more than our estimate in 2011.
As a result, we forecast that the horizontal well count should increase by over 30% in 2011 from 12,000 to approximately
16,000. Increasing horizontal drilling activity combined with fewer drilling days drives this massive increase in horizontal
wells that will need frac jobs.
The average number of stages per well should increase about 10% from 10 to 11. Again, this is probably light since oil
horizontals have typically been running over 20 stages per well and oil should represent the largest growth area.
Days required to pump a frac job should decrease about 12% from 6.0 to 5.3, which is a minor offset to the bullish
demand growth trends detailed above that is a result of frac operators becoming more efficient at their job. Sliding sleeves
and other technologies are now allowing companies to shave time off of jobs, freeing up horsepower.
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In summary, we expect the demand for frac horsepower to increase by over 20% in 2011 and another 6% in 2012 using what we feel
are some fairly conservative assumptions. Tweaking a few of the variables above by just a little to the bullish side could easily drive
frac demand growth up by well over 30% this year. We feel that the only risk to these demand growth estimates are sharper
reductions in frac days per pump job than we have modeled. The only question remaining is will net frac horsepower additions
swamp these robust growth forecasts?
Frac Horsepower Additions Should Set Record Highs in 2011
Assembling a frac fleet is not an overly complicated or expensive
North American Pressure Pumping Horsepower
endeavor. Identifying exactly how much frac horsepower is in
8,000,000
existence or has been added over the past few years is a very
Old Estimate
complicated exercise. For whatever reason, the larger industry
7,000,000
New Estimate
players think it is some competitive advantage to not disclose
6,000,000
their frac capacity. Whatever. For most people trying to
5,000,000
understand this industry, the road to understanding the size of
the North American frac fleet begins at the doorstep of Spears &
4,000,000
Associates. Beginning in 2003, Spears & Associates (an industry
3,000,000
analysis firm) has tried to track the industry’s total horsepower
capacity. As mentioned above, this is not an easy task. In fact,
2,000,000
the Spears experts are the first to admit the inherent difficulty
2005
2006
2007
2008
2009
with this exercise. Earlier this year, Spears meaningfully revised
Source: Spears
its horsepower estimates (as illustrated below) by approximately 15%, as new research shed more light on the situation. Are the
new numbers right? Of course not, but we think extremely highly of the Spears organization and these numbers are as good as
anyone (outside of the big three) will get. Their new analysis is shown in the adjacent chart.
So how much frac horsepower really exists and when was it added? We think it is fair to say that industry frac capacity has roughly
tripled over the past five years. Spears historical data highlights the tremendous growth in the industry’s capacity from 2005 to
2009. Our research suggests that there were probably slightly more net additions in 2007/2008 than Spears thinks and fewer 2009
additions than its numbers. Either way, its 2009 total capacity estimate of just under eight million is probably close. The real
question is how much capacity exists today? Using the Spears 2009 estimates as a starting point, we think there is close to 10
million horsepower that currently exists in North America. Going forward, the net growth in the industry’s capacity is going to be
driven by two key variables: 1) how much gross horsepower can we add? and 2) how much capacity will the industry lose to
attrition.?
Frac Manufacturing Capacity
(or Gross North American Horsepower Additions)
5,000,000
4,500,000
4,000,000
3,500,000
3,000,000
2,500,000
2,000,000
1,500,000
1,000,000
500,000
-
Gross Capacity Adds
2005
2006
2007
Source: Spears, IndustrySources, RJ Est.
2008
2009
2010 2011E 2012E 2013E
Manufacturing Capacity Increasing Meaningfully
For now we will focus on the amount of gross horsepower
that has been (and can be) added. It is important to make the
distinction that when we say gross horsepower, we are
strictly speaking of manufacturing capacity. We are not
factoring in whatever portion of this capacity is dedicated to
replacement or attrition within the existing fleet. In other
words, gross horsepower additions is not synonymous with
net frac fleet additions. What jumps off the page is our belief
that gross capacity adds spiked sharply in 2010 and will
continue to see meaningful growth over the next few years.
In 2007 and 2008, we believe the industry could manufacture
roughly two million horsepower per year. Today, we think
that number is above 2.5 million and will expand to
approximately 3.5 million by 2011. It is this analysis that has
everyone on Wall Street beginning to run for the exits.
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Frac Fleet Attrition and Increased Maintenance Is the Key to Understanding the Frac Supply/Demand Balance
Before you run out and sell your North American pressure pumping stocks, recognize that there is another variable in the
equation that we think has been underestimated by the market, and that is….attrition! Throughout our analysis of the frac
business and its supply chain, it has become clear that one of the single most overlooked factors is the potential for meaningfully
higher attrition rates going forward. The simple fact is that the industry is running the equipment exponentially harder than we ever
seen. Based on our model, we believe that we will start to see meaningfully higher levels of frac fleet attrition beginning in 2011 and
2012.
“Attrition” is somewhat of a slippery concept with a few
definitional issues worth clarifying. To do so, we must
understand the equipment involved. A frac truck consists of a
large trailer with the following three major components
mounted on top: 1) a fluid pump, 2) a transmission, and 3) a
diesel engine. The fluid pumps consist of a power end and a
fluid end. A power end houses the crankshaft, gears, bearings
and rods, which drive a piston (or plunger) into the fluid end.
The fluid end is a steel forging with usually three to five cavities.
The pistons moving in and out of the fluid end draw fluid from
one end and pump it out the other at a very high pressure. The
transmission and the diesel engine are rather self-explanatory in
that they provide the power and gearing necessary to operate
the pump. A frac truck today costs roughly $1.2 million and can
be divided into the following components, as shown in the
adjacent chart. .
Frac Truck Components
Total Cost: $1.2M
Engine
23%
Other
34%
Transmission
19%
Fluid End
5%
Power End
19%
Price as of Dec. 2010
Source: Industry Sources, RJ Est.
Since the cost of each of these three key components is fairly similar, we must define the life of a frac truck by the life of these three
major components. As expected, the life of each component varies considerably depending on: 1) who you talk to, 2) where the
equipment is working, and 3) how well the equipment is being maintained. In other words, there is no hard and fast rule. That said,
we have come up with some industry averages that we think capture the current state of the industry (based on comments from our
supply chain and end-user contacts).
Useful Life of Equipment
Fluid End
Hours
Low End
High End
Median
200
1,800
1,000
Power End Transmission
4,000
8,000
6,000
Years (anecdotes from manufacturers)
Historically
2-3 Years
10-15 years
Today
2- 6 months 2-3 years
Engine
2,000
10,000
6,000
6,000
15,000
12,000
10-15 years
2-3 years
10-15 years
5 years
Source: Industry sources, Raymond James & Associates Research.
The reality is that it is very difficult to pin down a definitive life-ending event for a frac truck today. In the past, equipment often
became obsolete before it really wore out. Today, critical components are wearing out and being replaced with increasing
frequency. For definitional purposes, we are assuming that the life of a frac truck is defined as the life of the diesel engine (including
one major overhaul), which is about 12,000 hours (plus or minus 5,000 hours). According to the table above, that means pumpers
will have to replace at least one transmission, one fluid pump, and numerous fluid ends during the life of that truck.
The fluid pumps have the shortest life. Remember, a fluid pump has a power end and a fluid end. The fluid end is the single
component that has seen the most extreme decline in useful life. This actually makes intuitive sense given that this is the main piece
of equipment exposed to high pressure fluids and corrosive proppants. Today, fluid ends are lasting anywhere from 200 to 1,800
hours, which means they need replacement every two to six months (down from the historical norm of two to five years). The
power ends of pumps are holding up much better, lasting on average 6,000 hours.
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Transmissions have the next longest life. Transmissions distribute the power from the engine to the fluid pump. There seems to be
a wide band of transmission life spans depending on how the equipment is run. We have heard that transmissions are lasting
anywhere from 1,000 to 20,000 hours depending on the type and operator. On average, however, it appears that in today’s frac
world, transmissions are lasting about 6,000 hours give or take a few thousand hours.
The diesel engines are the most resilient components on a frac truck. There also seems to be a wide difference between the rated
life (based on hours) and the actual life of a typical frac engine today. While most are rated to last over 15,000 hours, industry
participants tell us than the average life in the field (before a major overhaul) was about half the rated life (or about 8,000 hours).
For modeling purposes, we are going to split the difference between the manufacturer opinion and the user experience and assume
that a frac engine will last on average 12,000 hours.
Another definitional issue that we run into is how to distinguish between maintenance and attrition. Recent conference calls from
the pressure pumpers have cited out-of-service/maintenance time anywhere from 10% to 20%, which is more than double what it
was just a couple of years ago. In many cases, this out-of-service time is to address some of the items detailed above. For instance,
fluid ends are expendable items for which replacement takes a matter of hours and can be done on location in many cases. Other
items such as part replacement, minor overhauls, and general tune-ups must be done in a facility with trained mechanics.
Much like our demand assumptions, there are many variables that can alter our assumptions for attrition and overall supply. In our
model, we factor several variables to determine when we believe equipment reaches the end of its useful life. The following are a
few of the key assumptions in our model:
•
•
•
•
•
•
Useful life is currently 12,000 hours. In this, we are essentially defining the life of equipment by its longest lived asset – the
diesel engine. As illustrated above, many of the other components have shorter useful lives. Keep in mind that frac trucks
tend to be modular and individual components can be replaced without replacing the whole truck.
Work hours available. We are assuming that there are only 110 work hours available per week (out of 168 possible hours).
As most active basins have shifted to 24-hour frac operations, this may prove conservative.
Utilization drives hour usage. On a go-forward basis, this is determined by our various rig count assumptions.
Hours worked. The average hours worked per week has increased sharply over the past decade.
Maintenance time is growing from 5% in 2005 to 10% in 2010 and increasing gradually thereafter.
Intensity multiplier. Clearly, the higher pressure and rates that are being pumped today are causing more wear than ever
before. We try to capture this trend by applying an intensity multiplier that is based upon the industry’s weighting to
horizontal rigs.
Meaningfully Higher Equipment Intensity Drives Higher Attrition
Hopefully, we have nailed the point home that as drilling activity has rebounded with an increasing percentage dedicated to
horizontal drilling, the average frac truck is working considerably harder. The following graphs illustrate the magnitude of the
increased intensity on the equipment and our expectations for attrition. We estimate that in 2005, the average frac truck worked
approximately 1,500 hours per year. This compares to current activity in the area of 2,500 hours. As a result, we believe attrition
rates for the industry are set to rise meaningfully in the coming years. What this represents essentially is a lot of the incremental
capacity that we added in 2005 through 2008 cycling through the system to a point where it needs replacement/major
refurbishment. Historically, attrition has never been a huge factor in the pressure pumping market. Prior to the Barnett Shale rampup (starting around 2005), frac equipment would either rust or become obsolete before it really wore out. Starting in 2005, we
estimate that annual equipment attrition rates began creeping up from roughly 5% per year to over 10% today and will likely
jump above 15% per year by 2012.
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Frac Intensity
Industry Attrition
2400
Average Hour Usage per
Year per Truck
Forecast
2200
2000
1800
1600
Annual Attrition
2,500,000
14.0%
1,500,000
11.0%
1,000,000
8.0%
500,000
5.0%
2007
2008
2009
2010
2011E
2012E
20.0%
17.0%
% Attrition
2,000,000
1400
2005
2006
Source: Industry Sources, RJ Est.
Forecast
2.0%
2005 2006 2007 2008 2009 2010 2011E 2012E 2013E
2013E
Source: Industry Sources, RJ Est.
Net Frac Horsepower Adds Will Be Much Lower Than Many Understand
Yes, there is a massive slug of horsepower being delivered into
Net Horsepower Capacity Additions
the market place. We believe that the supply chain is geared up
3,000,000
to deliver upwards of 3.5 million gross horsepower in 2011 and
another 4.3 million in 2012 (or roughly 40% implied gross annual
2,500,000
growth in 2011). However, offsetting that supply surge, we are
2,000,000
convinced that the giant toll that today’s pressure pumping
applications are taking on the equipment will begin to manifest
1,500,000
into meaningfully higher attrition levels. If attrition levels surge
1,000,000
to 20% annually, then 40% gross equipment adds only leads to a
20% net increase in pressure pumping equipment. Specifically,
500,000
our model indicates that the North American frac fleet (net of
attrition) is set to grow by 2.6 million horsepower (about 25%)
2005 2006 2007 2008 2009 2010 2011E 2012E
in 2011 and another 2.0 million in 2012 (15%).
Source: Spears, Industry Sources, RJ Est.
So, When Will Increasing Frac Capacity Overwhelm Demand?
As detailed earlier, the demand side of the pressure pumping
story hinges primarily on the strength in horizontal drilling
activity. We remain bullish on North American horizontal
activity and are expecting the horizontal rig count to grow by
30% by year-end 2011. Likewise, we expect frac intensity to
continue to grow as operators become more proficient with
leading-edge completion technologies and efficiencies. We are
forecasting a conservative 20% increase in demand in 2011
(could be 30%) based on our rig count assumptions. In 2012,
that frac demand growth should begin to slow to 5-10%. On
the supply side of the equation, the discussion above shows that
we expect the net frac fleet (net of attrition) to grow by 2.6
million horsepower (25%) in 2011 and another 2.0 million in 2012
(15%).
% Attrition
2600
3,000,000
Attrition (Horsepower)
Hours Worked per Year
2800
2013E
North American Frac Fleet
18,000,000
16,000,000
Frac Horsepower
14,000,000
12,000,000
10,000,000
8,000,000
6,000,000
4,000,000
2,000,000
2005
2006
2007
2008
2009
2010 2011E 2012E 2013E
Source: Spears, Industry Sources, RJ Est.
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Combining these two, we anticipate that the North American frac business will remain relatively tight into early 2012. This means
the North American frac market should remain modestly undersupplied into 2012 as illustrated below.
NA Pressure Pumping Market
Supply & Demand Balance
3,000,000
2,500,000
2,000,000
16,000,000
14,000,000
12,000,000
Demand
1,500,000
Effective Capacity
1,000,000
10,000,000
Oversupplied
Balanced Market
2Q12
500,000
-
8,000,000
6,000,000
Balanced Market
(500,000)
(1,000,000)
4,000,000
(1,500,000)
(2,000,000)
2,000,000
-
Undersupplied
Source: Spears, Industry Sources, RJ Est.
1Q04
3Q04
1Q05
3Q05
1Q06
3Q06
1Q07
3Q07
1Q08
3Q08
1Q09
3Q09
1Q10
3Q10
1Q11 E
3Q11 E
1Q12 E
3Q12 E
1Q13 E
3Q13 E
1Q04
3Q04
1Q05
3Q05
1Q06
3Q06
1Q07
3Q07
1Q08
3Q08
1Q09
3Q09
1Q10
3Q10
1Q11E
3Q11E
1Q12E
3Q12E
1Q13E
3Q13E
(2,500,000)
Source: Spears, Industry Sources, RJ Est.
As shown above, frac horsepower demand should continue to outpace net capacity adds into early 2012. If the U.S. rig count
remains relatively flat and the net capacity adds continue to surge, then we should expect the market to be balanced or even
modestly oversupplied by late 2012. The natural state of this business is for capacity to be added until returns fall back into a more
normalized range (we will discuss that range later). Today, we think capacity additions are generating internal rates of return well
above 50%. That will come down and lower pricing will be the culprit. The question for investors is when will the prices deteriorate?
How Will Higher Attrition Rates Change the Economics of the Business?
If, in fact, the industry is chewing through the equipment meaningfully faster than we have ever seen, shouldn’t that mean higher
maintenance and depreciation expense for companies? The short answer is yes. As illustrated below, we estimate that
maintenance cap ex was running in the $500 million range in 2005. Today, we think that maintenance costs are at least 2.5-4x
higher for the industry. Why? Because the pressure pumping equipment is wearing out faster than ever before. To put it in
perspective, we believe that a frac truck today will last about five years (assuming today’s usage rate) before the engine (and the
entire unit) must be totally replaced. During that period, the truck that originally cost about $1.2 million to build will need to replace
about 12 fluid ends (about $700,000 total), one transmission (about $225,000), and one power end of the fluid pump (about
$225,000). In addition, the engine will need at least one overhaul (about $100,000) and numerous other maintenance-related costs
before the end of its five-year life. In other words, operators will have to pay roughly the equivalent newbuild cost of that unit in
maintenance over the five-year life of that truck. A decade ago, the truck would have lasted a decade and maintenance would have
been roughly one-third of today’s number. Likewise, companies may have been able to depreciate this equipment over a ten-year
period a decade ago. Clearly, these depreciation times will come down and depreciation costs will go up (and/or maintenance must
go up) to account for the shorter equipment life.
Annual Maintenance Capex (Industry-Wide)
Annual Maintenance Capex (per truck)
$3,500
$650,000
$600,000
$2,500
(in 000,000s)
(in 000,000s)
$3,000
$2,000
$1,500
$550,000
$500,000
$450,000
$400,000
$350,000
$1,000
$300,000
$500
$250,000
$200,000
$0
$150,000
2005
2006
Sources: Industry Sources, RJ Est.
2007
2008
2009
2010
2011E 2012E
2005
2006
2007
2008
2009
2010
2011E 2012E
Sources: Indsutry Sources, RJ Est.
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These shorter lives also mean that newbuild economics are probably different than prior cycles. In today’s high margin market, we
estimate that companies are getting what appears to be a 1-year to 1.5-year payback on new equipment. Assuming an eight-year
life and static operating margins over the next five years, that implies an incredible 77% internal rate of return; however, those
returns cannot last. Unfortunately, the equipment is not lasting eight years and the margins are likely to fall from here. That said, if
we plug in more realistic future margins and equipment lives, the returns today still suggest a very healthy 72% internal rate of
return for equipment built today. The problem is that this has been a hyper-cyclical business and the returns must be outstanding in
the good years to afford the lean years. That means that newbuilds will likely begin to fade when industry operating margins fall to
the 20% range and static internal rates of return fall to the sub-50% range. The following table shows a rough rendition of the
unlevered math for newbuild economics. At today’s margins, companies are making nearly $1,000/hp in EBITDA per year. Clearly
this cannot last forever (hence, massive newbuilds). By 2014, we estimate that EBITDA/hp will fall to approximately $800/hp and
operating margins will fall to 22%. At that point, we think industry margins and profitability per horsepower will stabilize or high
attrition may drive the industry to run short of horsepower again.
Newbuild Economics
2005
$1,000
2006
$1,000
2007
$1,100
2008
$1,100
2009
$1,000
2010
$1,100
2011E
$1,100
2012E
$1,100
2013E
$1,100
2014E
$1,100
2015E
$1,100
REV/HP
Labor
Materials and Logistics
Maintenance
Op Costs
$3,287
$885
$1,217
$111
$2,212
$3,218
$773
$1,159
$111
$2,043
$2,688
$666
$999
$111
$1,775
$2,614
$677
$1,015
$150
$1,842
$1,577
$480
$721
$150
$1,351
$2,650
$650
$975
$250
$1,875
$3,276
$699
$1,024
$300
$2,023
$3,510
$751
$1,075
$300
$2,126
$3,430
$789
$1,129
$300
$2,218
$3,079
$789
$1,129
$300
$2,218
$2,915
$789
$1,129
$300
$2,218
EBITDA
Cost per Horsepower
(All Figures on a Per Horsepower Basis)
$1,074
$1,175
$913
$773
$226
$775
$1,253
$1,379
$1,176
$898
$766
EBITDA margin
33%
37%
34%
30%
14%
29%
38%
39%
34%
29%
26%
Depr
100
100
110
137.5
125
137.5
220
220
220
220
220
$974
$1,075
$803
$635
$101
$638
$1,111
$1,159
$956
$678
$546
Op Income
Op Margin
30%
33%
30%
24%
6%
24%
34%
33%
28%
22%
19%
$1,074
$341
$733
$1,175
$376
$799
$913
$281
$632
$773
$222
$550
$226
$35
$190
$775
$223
$552
$1,253
$389
$864
$1,379
$406
$973
$1,176
$335
$842
$898
$237
$661
$766
$191
$575
Projected Life
Projected IRR
Projected Payback
10
73%
1.4
10
79%
1.3
10
56%
1.7
9
48%
2.0
9
10%
5.3
9
48%
2.0
8
77%
1.3
8
87%
1.1
8
75%
1.3
8
58%
1.7
8
49%
1.9
Actual Life
Actual IRR
Actual Payback
6.5
65%
1.3
6.5
59%
1.5
6.5
48%
2.4
6
45%
2.5
6
59%
1.9
5
66%
1.4
5
72%
1.2
5
64%
1.3
5
52%
1.5
5
44%
1.9
5
42%
2.0
EBITDA
Tax
Cash Flow
Source: Industry reports, Spears, Raymond James & Associates Research.
When Will Pressure Pumping Margins Peak and How Will Industry Earnings React?
As we said at the beginning, the pressure pumping business will overbuild eventually. Frac fleet returns cannot remain in the 50% or
higher range indefinitely. One purpose of this exercise is to figure out when margins will begin to fall, when earnings will be hit, and
how quickly the cycle will recover. As shown in the following graph, we think pressure pumping margins will likely peak in late 2011
and then experience a gradual decline through mid-2012. This is a much more gradual decline than prior downcycles that were
largely driven by commodity prices and activity collapses. Specifically, we are modeling average (not leading edge) pricing to
increase through mid-2011, albeit at a decelerated pace, therefore driving margins growth through mid-2011. Revenue, on the
other hand, should continue to increase further through late 2012 as the industry delivers more capacity (and higher volumes offset
lower pricing). From an overall earnings perspective, this should still drive EPS growth through 2012. In other words, even though
pricing will likely peak sometime in mid-2011, the industry should still deliver solid earnings growth (approximately 20%) in 2012 due
to higher volumes and modestly lower pricing.
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Industry Operating Income
$16,000
40.0%
$14,000
35.0%
$12,000
30.0%
$10,000
25.0%
$8,000
20.0%
15.0%
$6,000
$4,000
Revenues
$2,000
Margins
10.0%
5.0%
0.0%
1Q07
3Q07
1Q08
3Q08
1Q09
3Q09
2009
2Q10
4Q10
2Q11E
4Q11E
2Q12E
4Q12E
2Q13E
4Q13E
2Q14E
4Q14E
2Q15E
$-
Source: Spears, Industry Sources, RJ Est.
(in 000,000s)
Revenues (in 000.000s)
Industry Revenue & Margins
$18,000
$16,000
$14,000
$12,000
$10,000
$8,000
$6,000
$4,000
$2,000
$-
Sources: Spears, Industry Sources, RJ Est.
That Is a Great Analysis Raymond James, But What Do We Do With the Stocks?
As we all know, the market is a future-discounting mechanism. The skeptics are already pointing to looming capacity and saying
“game over” for the frac guys. Let’s face it, some of the pressure pumping stocks have doubled, even tripled, over the course of
2010, and for some, profit-taking is a prudent measure. Pressure pumping names have been some of our favorite names and that
has been the right call. As we said earlier, getting out of pressure pumping now is the easy trading call that does not require a lot
of fundamental insight. For the rest of the investors who may not be as short-term focused, the question becomes “where do the
pumping stocks go from here?” In short, we think they still have room to go up, despite the sentiment headwinds. Yes, stock
volatility will increase but the industry fundamentals paint a more robust picture than many are leading investors to believe. The
main reasons for this are as follows:
1) Our analysis indicates that we likely have two to four more quarters of industry margin expansion. Historically, the stocks
do not peak until margins peak.
2) Improving margins should lead to meaningful positive EPS revisions. Typically, this drives stocks higher.
3) We do not believe the industry will experience a commodity price-driven activity collapse like we saw in 2008/2009 (see our
prior research for more details on this).
4) The threat of new frac horsepower supply is not as destructive to the industry’s longer-term profitability (in 2012 and
beyond) due to higher attrition levels.
5) From a valuation perspective, most North American pressure pumping names (Baker Hughes, Complete Production
Services, Halliburton, and Patterson-UTI Energy) trade at historically attractive valuations at approximately 12x 2012 EPS.
In summary, we remain relatively bullish on the pressure pumping space and think it is still too early to throw in the towel. Yes, we
will ultimately overbuild. Yes, the industry is adding substantial capacity. Yes, the easy money has been made in the pumping
stocks. However, that said, we think industry fundamentals improve into a 2012 event as opposed to many that are calling for an
early 2011 peak.
When Have the Stocks Peaked in Previous Cycles?
To begin with, investors need to realize that the most recent prior cyclical stock price peaks were highly correlated with a
commodity (usually natural gas) price collapse that spurred a subsequent drilling activity collapse. While we are expecting weak
natural gas prices over the next few years, we are not expecting a commensurate collapse in overall U.S. drilling activity in the near
future. That is because we expect robust oil prices to support oil and liquids-rich drilling, which should more than offset a falling gas
rig count. More importantly, for pressure pumping activity, we expect the trend toward the pressure pumping-intensive horizontal
activity to continue to increase over the next few years. Put simply, we expect this cyclical peak to be much more subdued than
recent cyclical peaks because it will be driven by capacity additions rather than demand destruction. With that as a background, it is
interesting to see how the pressure pumping stocks acted during the last industry downturn. If we dial back the clock five years,
there were two relative “pure plays” in pressure pumping (BJ Services and Superior Well Services) and one perceived pressure
pumping levered company (Halliburton). As illustrated in the following graphs, all three of these names saw the stock prices peak
in the same time frame as operating margins peaked in the 2006 downturn and again in the 2008 downturn. Again, remember
that these downturns were driven by oil and gas price-driven activity (or demand) collapses, not capacity-driven downturns.
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Stock Price vs. Pressure Pumping Operating Margin
Superior Well Services
Halliburton
$35
33%
$30
20%
$70
$30
25%
$25
5%
$25
18%
$20
10%
$20
-10%
$15
3%
$15
-25%
$10
-5%
$10
-40%
Margin
$5
-20%
Avg Stock Price
Margin
$0
1Q05
2Q05
3Q05
4Q05
1Q06
2Q06
3Q06
4Q06
1Q07
2Q07
3Q07
4Q07
1Q08
2Q08
3Q08
4Q08
1Q09
2Q09
3Q09
4Q09
$0
-13%
32.5%
$50
26.0%
$40
19.5%
$30
13.0%
-55%
$20
6.5%
-70%
$10
0.0%
1Q05
2Q05
3Q05
4Q05
1Q06
2Q06
3Q06
4Q06
1Q07
2Q07
3Q07
4Q07
1Q08
2Q08
3Q08
4Q08
1Q09
2Q09
3Q09
4Q09
Avg Stock Price
Source: Bloomberg, Company Reports
Source: Bloomberg, Company Reports
39.0%
$60
3Q05
4Q05
1Q06
2Q06
3Q06
4Q06
1Q07
2Q07
3Q07
4Q07
1Q08
2Q08
3Q08
4Q08
1Q09
2Q09
3Q09
4Q09
$5
45.5%
Avg Stock Price
Margins
North American C&P Margins
$80
Average Stock Price
35%
Operating Margin
$35
Average Stock Price
40%
North American Margins
Average Stock Price
BJ Services
$40
Source: Bloomberg, Company Reports
From an earnings perspective, the story is not as clean, since for Halliburton and Superior Well Services the earnings per share (EPS)
continued to be strong through the entire 2006 correction while BJ Services’ EPS experienced only a modest fall beginning one
quarter after the stocks peaked.
Stock Price vs. EPS
Superior Well Services
Halliburton
$0.76
$30
$0.50
$30
$0.63
$25
$0.49
$20
$0.35
$15
$0.21
$5
$0.08
Avg Stock Price
EPS
1Q05
2Q05
3Q05
4Q05
1Q06
2Q06
3Q06
4Q06
1Q07
2Q07
3Q07
4Q07
1Q08
2Q08
3Q08
4Q08
1Q09
2Q09
3Q09
4Q09
$0
Source: Bloomberg, Company Reports
$20
-$0.50
$15
-$1.00
$10
-$0.06
$5
-$0.20
$0
Avg Stock Price
EPS
-$1.50
-$2.00
Source: Bloomberg, Company Reports
EPS
$0.00
3Q05
4Q05
1Q06
2Q06
3Q06
4Q06
1Q07
2Q07
3Q07
4Q07
1Q08
2Q08
3Q08
4Q08
1Q09
2Q09
3Q09
4Q09
$10
$25
$1.20
Avg Stock Price
EPS
$70
$60
$1.00
$0.80
$50
$40
$0.60
$30
EPS
$35
$80
$0.40
$20
$0.20
$10
$0
$0.00
1Q05
2Q05
3Q05
4Q05
1Q06
2Q06
3Q06
4Q06
1Q07
2Q07
3Q07
4Q07
1Q08
2Q08
3Q08
4Q08
1Q09
2Q09
3Q09
4Q09
$1.00
Average Stock Price
$35
Average Stock Price
$0.90
EPS
Average Stock Price
BJ Services
$40
Source: Bloomberg, Company Reports
After examining pressure pumping stocks in the most recent prior two downturns (2006 and 2008), we are not sure that the
rearview mirror tells us much other than that the market does seem to be forward-looking (at least by a quarter). To begin with, we
think that the next capacity-driven downcycle will be a much more subdued downturn than the most resent two demand-driven
downcycles. Secondly, the higher industry attrition rates suggest that the next downcycle will self-correct much faster than we may
have seen in the past. Bottom line: If we assume that the market will be a quarter ahead of a margin and/or earnings peak, our
analysis suggests that it is still too early to sell the pressure pumping stocks.
Conclusion: The Pressure Pumping Party Ain’t Over Yet
There is no hotter debate among energy investors than the pressure pumping market. 2010 was clearly a monster year for pressure
pumping stocks, but as the industry gears up to deliver an unprecedented level of capacity into an undersupplied market, a sense of
fear and panic seems to be gripping the investment community. While we unequivocally agree that the industry will overbuild at
some point, we believe that this is more of an early 2012 event as opposed to the growing consensus opinion of mid-2011. The
primary differences between us and consensus include: 1) demand will continue to increase driven by growing horizontal drilling and
increased frac intensity, and 2) attrition rates are meaningfully higher than the industry has ever seen which should cushion the
effects of incoming supply. As a result, we believe that we have at least two more quarters of expanding margins and climbing EPS
estimates, which should translate to superior stock performance in early 2011.
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2009
1Q10
2Q10
3Q10
4Q10
2010
1Q11E
2Q11E
3Q11E
4Q11E
2011E
1Q12E
2Q12E
3Q12E
4Q12E
2012E
2013E
12,696,467 13,244,539 13,649,616 14,078,625
1,075,000
1,075,000
1,075,000
1,075,000
(532,654)
(526,928)
(669,922)
(645,992)
4.4%
4.2%
5.1%
4.7%
542,346
548,072
405,078
429,008
14,078,625
4,300,000
(2,375,496)
19.5%
1,924,504
15,918,178
4,550,000
(2,710,446)
19.3%
1,839,554
12,696,467 13,244,539 13,649,616 14,078,625
(1,565,551) (1,640,063) (1,697,420) (1,758,248)
-12%
-12%
-12%
-12%
11,130,915 11,604,476 11,952,197 12,320,377
14,078,625
(1,747,086)
-12%
12,331,539
15,918,178
(1,987,986)
-12%
13,930,193
Supply
Total Capacity
Gross Capacitiy Adds
Annual Attrition
Attrition %
Net Capacity Added
7,500,000 8,025,000 8,550,000
702,724
646,170
668,115
(452,724) (121,170) (143,115)
6.2%
1.6%
1.8%
250,000
525,000
525,000
9,075,000
698,811
(173,811)
2.0%
525,000
9,600,000
679,341
(154,341)
1.7%
525,000
9,600,000 10,339,573 11,059,606 11,648,098 12,154,120
2,692,437
900,000
900,000
900,000
900,000
(592,437)
(160,427)
(179,967)
(311,508)
(393,977)
7.9%
1.7%
1.7%
2.8%
3.4%
2,100,000
739,573
720,033
588,492
506,023
Total Capacity
Down for Maintenance
Maintenance Downtime %
Effective Capacity
7,500,000 8,025,000 8,550,000
(457,952) (652,444) (802,654)
-6%
-8%
-9%
7,042,048 7,372,556 7,747,346
9,075,000
9,600,000
(939,688) (1,042,519)
-10%
-11%
8,135,312
8,557,481
9,600,000 10,339,573 11,059,606 11,648,098 12,154,120
(929,572) (1,165,576) (1,286,256) (1,394,491) (1,497,756)
-10%
-11%
-12%
-12%
-12%
8,670,428
9,173,997
9,773,349 10,253,607 10,656,364
12,154,120
3,600,000
(1,045,880)
10.9%
2,554,120
2,554,120
12,154,120
(1,434,127)
-12%
10,719,993
Max Hours/Week
% maintenance
Effective Hr/Wk
% utilization
Hr/Wk Worked
Intensity Multiplier
Real Hours/Week
110
-6%
103
72%
75
0.44x
33
110
-8%
101
100%
101
0.49x
50
110
-9%
100
100%
100
0.51x
51
110
-10%
99
100%
99
0.51x
50
110
-11%
98
100%
98
0.51x
50
110
-10%
99
100%
99
0.50x
50
110
-11%
98
100%
98
0.53x
52
110
-12%
97
100%
97
0.54x
53
110
-12%
97
100%
97
0.54x
53
110
-12%
96
100%
96
0.55x
53
110
-12%
97
100%
97
0.54x
53
110
-12%
96
100%
96
0.56x
54
110
-12%
96
98%
94
0.57x
53
110
-12%
96
100%
96
0.56x
54
110
-12%
96
100%
96
0.56x
54
110
-12%
96
99%
96
0.56x
54
110
-12%
96
96%
93
0.57x
53
Weeks/Period
Hours/Period
Equipment Life (hrs)
Useful Life (Yrs)
50
1648
12000
5.0
12.5
621
12000
12.5
632
12000
12.5
627
12000
12.5
624
12000
50
2504
12000
4.6
12.5
651
12000
12.5
658
12000
12.5
658
12000
12.5
662
12000
50
2630
12000
4.5
12.5
676
12000
12.5
668
12000
12.5
677
12000
12.5
675
12000
50
2696
12000
4.5
50
2648
12000
4.5
2009
1Q10
2Q10
3Q10
4Q10
2010
1Q11E
2Q11E
3Q11E
4Q11E
2011E
1Q12E
2Q12E
3Q12E
4Q12E
2012E
2013E
Demand
U.S.
U.S. Rig Count
Horizontal Rig Count
Vertical Rig Count
% Horizontal
Average Frac Job (US)
Drilling Days
Well Count
Horsepower per Job
Stages/Well
Day Pumping
Realistic Utilization
Total HZ Frac Demand
Total Frac Demand Per HZ Rig
Total Demand Per Vertical Rig
Total U.S. Demand
1089
453
636
42%
1345
656
689
49%
1506
781
725
52%
1618
883
735
55%
1687
931
756
55%
1539
813
726
53%
1729
978
751
57%
1748
1026
722
59%
1757
1078
679
61%
1764
1132
632
64%
1750
1053
696
60%
1750
1140
609
65%
1750
1149
601
66%
1750
1157
592
66%
1750
1166
584
67%
1750
1153
596
66%
1800
1225
574
68%
26
6,346
31850
9
6.0
85%
3,919,279
8,647
865
4,469,016
25
2,388
32500
10
6.0
85%
6,019,765
9,176
918
6,652,024
25
2,843
32500
10
6.0
85%
7,166,824
9,176
918
7,832,118
25
3,214
32500
10
6.0
85%
8,102,824
9,176
918
8,777,294
25
3,389
32500
10
6.0
85%
8,543,294
9,176
918
9,237,035
25
11,834
32500
10
6.0
85%
7,458,176
9,176
918
8,124,618
24
3,707
34125
11
5.3
85%
8,585,009
8,782
878
9,244,946
24
3,892
34125
11
5.3
85%
9,014,260
8,782
878
9,647,957
24
4,086
34125
11
5.3
85%
9,464,973
8,782
878
10,061,503
24
4,291
34125
11
5.3
85%
9,938,222
8,782
878
10,493,574
24
15,976
34125
11
5.3
85%
9,250,616
8,782
878
9,861,995
23
4,511
35831
12
4.7
85%
9,873,450
8,660
866
10,401,169
23
4,545
35831
12
4.7
85%
9,947,501
8,660
866
10,467,815
23
4,579
35831
12
4.7
85%
10,022,107
8,660
866
10,534,961
23
4,613
35831
12
4.7
85%
10,097,273
8,660
866
10,602,610
23
18,248
35831
12
4.7
85%
9,985,083
8,660
866
10,501,639
22
20,276
37623
13
4.3
85%
10,717,494
8,746
875
11,219,550
221
67
154
30%
69%
469
235
235
50%
-65%
163
90
73
55%
121%
360
180
180
50%
14%
412
206
206
50%
351
178
173
51%
15%
474
308
166
65%
-60%
190
123
66
65%
100%
379
227
152
60%
0%
379
227
152
60%
355
222
134
62%
25%
474
308
166
65%
-60%
190
123
66
65%
100%
379
227
152
60%
0%
379
227
152
60%
355
222
134
62%
355
222
134
62%
15
5,706
16500
5
4
65%
1,587,385
6,769
677
1,746,123
21%
15
2,181
16500
5
4
65%
606,862
6,769
677
656,514
8%
15
4,380
16500
5
4
65%
1,218,462
6,769
677
1,340,308
13%
15
5,013
16500
5
4
65%
1,394,462
6,769
677
1,533,908
14%
15
7,494
17325
6
3.8
65%
2,079,508
6,752
675
2,191,482
19%
15
2,998
17325
6
3.8
65%
831,803
6,752
675
876,593
8%
15
5,534
17325
6
3.8
65%
1,535,637
6,752
675
1,638,013
14%
15
5,534
17325
6
3.8
65%
1,535,637
6,752
675
1,638,013
14%
15
7,494
18191
7
3.7
65%
2,128,897
6,913
691
2,243,529
18%
15
2,998
18191
7
3.7
65%
851,559
6,913
691
897,412
8%
15
5,534
18191
7
3.7
65%
1,572,108
6,913
691
1,676,915
14%
15
5,534
18191
7
3.7
65%
1,572,108
6,913
691
1,676,915
14%
15
5,390
18191
7
3.7
65%
1,531,168
6,913
691
1,623,693
15
5,390
19101
8
3.6
65%
1,567,533
7,077
708
1,662,256
Canada
Canadian Rig Count
Horizontal Rig Count
Vertical Rig Count
% Horizontal (Estiamte)
Average Frac Job (US)
Drilling Days
Well Count
Horsepower per Job
Stages/Well
Day Pumping
Realistic Utilization
Total HZ Frac Demand
Total Frac Demand Per HZ Rig
Total Demand Per Vertical Rig
Total Canada Demand
15
1,632
16170
4
4
65%
444,816
6,634
663
547,108
15
4,320
16500
5
4
65%
1,201,792
6,769
677
1,319,213
15
5,390
17325
6
3.8
65%
1,495,646
6,752
675
1,586,025
Total Demand
North American Demand (hp)
5,016,124
8,398,147
8,488,631
Company Citations
Company Name
Baker Hughes, Inc.
Basic Energy Services, Inc.
Complete Production Services Inc.
Halliburton
Nabors Industries Ltd.
Patterson-UTI Energy, Inc.
10,117,602
10,770,943
9,443,831
Ticker
BHI
BAS
CPX
HAL
NBR
PTEN
11,436,427
10,524,550
11,699,515
Exchange
NYSE
NYSE
NYSE
NYSE
NYSE
NASDAQ
12,131,587
11,448,020
12,644,699
11,365,227
12,211,876
12,279,525
Currency Closing Price RJ Rating
$
56.60
2
$
14.62
3
$
26.34
1
$
38.45
1
$
22.76
1
$
19.99
1
12,125,332
12,881,806
RJ Entity
RJ & Associates
RJ & Associates
RJ & Associates
RJ & Associates
RJ & Associates
RJ & Associates
Notes: Prices are as of the most recent close on the indicated exchange and may not be in US$. See Disclosure section for rating
definitions. Stocks that do not trade on a U.S. national exchange may not be approved for sale in all U.S. states. NC=not covered.
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Raymond James & Associates (U.S.) definitions
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Underperform (MU4) Expected to underperform the S&P 500 or its sector over the next six to 12 months and should be sold.
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Suspended (S) The rating and price target have been suspended temporarily. This action may be due to market events that made coverage
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In transacting in any security, investors should be aware that other securities in the Raymond James research coverage universe might carry a
higher or lower rating. Investors should feel free to contact their Financial Advisor to discuss the merits of other available investments.
Raymond James Ltd. (Canada) definitions
Strong Buy (SB1) The stock is expected to appreciate and produce a total return of at least 15% and outperform the S&P/TSX Composite Index
over the next six months.
Outperform (MO2) The stock is expected to appreciate and outperform the S&P/TSX Composite Index over the next twelve months.
Market Perform (MP3) The stock is expected to perform generally in line with the S&P/TSX Composite Index over the next twelve months and
is potentially a source of funds for more highly rated securities.
Underperform (MU4) The stock is expected to underperform the S&P/TSX Composite Index or its sector over the next six to twelve months
and should be sold.
Raymond James Latin American rating definitions
Strong Buy (SB1) Expected to appreciate and produce a total return of at least 25.0% over the next twelve months.
Outperform (MO2) Expected to appreciate and produce a total return of between 15.0% and 25.0% over the next twelve months.
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Raymond James European Equities rating definitions
Strong Buy (1) Absolute return expected to be at least 10% over the next 12 months and perceived best performer in the sector universe.
Buy (2) Absolute return expected to be at least 10% over the next 12 months.
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Sell (4) Expected absolute drop in the share price of more than 10% in next 12 months.
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Out of approximately 816 rated stocks in the Raymond James coverage universe, 53% have Strong Buy or Outperform ratings (Buy), 40% are
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Suitability Categories (SR)
For stocks rated by Raymond James & Associates only, the following Suitability Categories provide an assessment of potential risk factors for
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Raymond James Relationship Disclosures
Raymond James expects to receive or intends to seek compensation for investment banking services from the subject companies in the
next three months.
Company Name
Disclosure
Baker Hughes, Inc.
Raymond James & Associates received non-investment banking securities-related
compensation from BHI within the past 12 months.
Halliburton
Raymond James & Associates received non-investment banking securities-related
compensation from HAL within the past 12 months.
Nabors Industries Ltd.
Raymond James & Associates received non-investment banking securities-related
compensation from NBR within the past 12 months.
Patterson-UTI Energy,
Inc.
Raymond James & Associates makes a NASDAQ market in shares of PTEN.
Raymond James & Associates received non-investment banking securities-related
compensation from PTEN within the past 12 months.
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Risk Factors
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revenues and earnings; (2) Issues relating to major competitors or market shares or new product expectations could change investor attitudes
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