Exploration & Production
David Amoss | 504.582.2638 davida@howardweil.com
Blaise Angelico | 504.582.2553 blaisea@howardweil.com
Joseph Bachmann | 504.582.2637 josephb@howardweil.com
Brian Corales | 504.582.2555 brianc@howardweil.com
Blake Fernandez | 504.582.2528 blakef@howardweil.com
Peter Kissel | 504.582.2881 peterk@howardweil.com
Abigail Mayo | 713.393.4511 abigailm@howardweil.com
Holly Stewart | 713.393.4512 hollys@howardweil.com
Richard Roberts | 504.582.2560 richardr@howardweil.com
June 1, 2011
Eagle Ford Shale
Not All Areas are Created Equal
Quick Take: Since its discovery as a commercially
viable zone in 2008, the Eagle Ford shale has quickly
become one of the hottest onshore shale plays in the US,
evidenced by a 170% increase in rig count over the past
year and a ~50% increase since January 2011. While we
think most investors understand the basics of the Eagle
Ford, we believe this is the year where we will see better
differentiation between the various areas of the play – in
short, economic returns can vary significantly from one
drilling location to another, often in relatively close
geography.
Trends: We have started to see the sweet spots of the
trend develop as companies have ramped up activity
over the past 12 months. One significant challenge in
differentiating Eagle Ford locations is that one county
can have areas that are dry gas and other areas that are
all oil, with a transitioning zone in between, making a
granular focus necessary to measure the reservoir
characteristics of a specific drilling location and the
resulting expected returns.
Highest Returns: We have done our best to determine
which regions of the play provide the best returns, based
on available public well data. To highlight the varying
returns thus far, we have identified 3 Core geographic
areas which we think are all highly economic. In our
estimation, the best economic returns in the play are
generated across a relatively narrow swath of acreage
running from southwest to northeast in the
Condensate/Volatile Oil Window in La Salle,
McMullen, Live Oak, Karnes, DeWitt, and Gonzales
counties (outlined in Figure 1). While these are not
necessarily the highest EUR wells, the higher relative
liquid component provides better economic returns in
the current commodity environment.
Detailed Eagle Ford Operator Index – Page 14
Figure 1: Eagle Ford Core Areas
Source: HPDI, Howard Weil
Figure 2: Eagle Ford Leverage, Acreage and Valuation
Ticker
SM
MHR
SFY
GDP
HK
NFX
ROSE
EOG
MUR
CRZO
CHK
PVA
PXD
CRK
COG
PXP
EP
APC
MRO
PQ
COP
RDS
XOM
BP
Acreage/
EV
50.3
41.1
37.4
32.5
30.0
26.5
24.3
18.1
16.2
13.4
13.0
11.1
9.2
8.9
8.3
7.7
6.0
4.0
2.9
2.7
1.2
1.0
0.3
0.2
Ticker
EOG
CHK
NFX
HK
SM
RDS
COP
MUR
APC
EP
MRO
XOM
PXD
SFY
ROSE
COG
PXP
GDP
BP
CRZO
MHR
CRK
PVA
PQ
Acreage
(net)
595,000
450,000
335,000
331,600
250,000
250,000
240,000
220,000
200,000
170,000
120,000
120,000
117,000
79,000
65,000
60,000
60,000
40,000
40,000
28,000
25,074
18,000
12,700
1,600
HW EF NonActive
proved Value
Op Rigs
per Share
20
$14.28
18
$2.88
3
$4.69
14
$19.12
3
$28.56
3
*
12
*
4
$11.31
9
$2.82
3
$1.10
1
*
2
*
8
$21.86
4
$15.74
2
$21.53
1
$0.00
5
$3.33
2
$12.74
8
*
1
$10.70
NA
NA
1
$5.18
3
$6.44
1
$0.00
Source: Howard Weil, SmithSTATS
* Unproved Property values not segregated by play.
All relevant disclosures and certifications begin on Page 33 of this report.
Howard Weil Incorporated Œ 1100 Poydras Street, Suite 3500 ŒNew Orleans, LA 70163
June 1, 2011
Operators Involved
Eagle Ford Shale – Not All Areas are Created Equal
Figure 3: Eagle Ford Hydrocarbon Windows
Within the Howard Weil coverage universe, we cover
nearly all of the domestic producers involved in the
Eagle Ford ranging from the founder of the play,
Petrohawk, to one of the smallest operators in the
play, PetroQuest. Additionally, many of the
Companies have announced Joint Venture agreements
to help fund development, including Chesapeake,
Pioneer and Anadarko, each of which were greater
than $1 billion for implied valuations of more than
$10,000/acre. In total, there have been over 600,000
net acres of announced transactions for ~$7 billion.
Operators in the Core Areas of the Play:
Companies under coverage with acreage in the
defined Core liquids-rich area (Area #3 in Figure 5)
include EOG, COP, HK (Black Hawk), PXD and
PXP. While there are several other producers that
have some acreage in and around the Core, these
companies have a highest concentration. Further,
additional upstream participants with acreage in the
high-return, slightly gassier area in northern Webb
County/southern Dimmit County include SM, ROSE,
CHK, and APC. We believe this region has very
competitive economics in the current commodity
environment, which could further improve if gas
prices increase. Several other producers have highly
prospective acreage, which looks to be very economic
with varying levels of delineation to date, including
MUR, EP, CRZO, SFY, HK (Hawkville), NFX, and
GDP. Results from these producers will likely
become better understood as additional drilling
occurs.
Geologic Summary: The Eagle Ford shale is a
Cretaceous era formation with high carbonate content,
bounded above by the Austin Chalk/Anacacho and
below by the Buda. The reservoir ranges from 140’ to
450’ thick and migrates deeper from north to south.
The most sought-after geographic regions of the play
typically exhibit good porosity, high brittleness, and
low clay content. Generally, the northern portion of
the play is more oily while the southern portion is
largely dry gas. The middle geographic segment
yields condensate and wet gas, and it is widely
believed that the gas content enables the oil molecules
to flow through the rock with less resistance, leading
to higher reservoir pressure and flow rates vs. the Oil
Window to the north. The EIA map, in Figure 3,
highlights the three Eagle Ford windows: Oil Window
in green, Condensate/Wet Gas Window in yellow, and
Dry Gas Window in red.
Source: EIA, October 2010
Optimal Drilling and Completion Evolving: As the
play has matured, drilling continues to become more
efficient, as operators have markedly improved their
drilling days with some wells now being drilled in 15
days or less. The optimal completion design has also
evolved, with laterals currently ~5,000’ and frac
intervals ranging from 250’ to 350’ apart. However,
operators continue to experiment with new methods to
both increase recovery and decrease cost. Completions
have become an increasingly significant factor in well
costs recently, running 50% or higher of total D&C
costs, and service equipment has been in short supply
with the increasing drilling activity. Figure 4 shows
general D&C operational characteristics by region,
with higher total costs in the southern, deeper area of
the play.
Figure 4: Eagle Ford Operations by Area
Source: El Paso presentation
Page 2 of 33
Howard Weil
June 1, 2011
Eagle Ford Shale – Not All Areas are Created Equal
well liquids content. While not peak returns, gassier
acreage with liquids pricing uplift can be very
attractive and could get even more attractive if/when
gas prices increase. We think the biggest near-term
risks to Eagle Ford margins is service availability and
cost inflation, which are becoming more pronounced
as the rig count increases.
Regional Drilling History: The Eagle Ford shale
geographic region has seen significant drilling activity
over time, with the Austin Chalk, Buda, Lobo, and
Olmos zones, all being popular target formations
previously. Specifically, the Eagle Ford shale is
believed to have been the source rock for Austin
Chalk producers in the past, and reservoir drainage,
although not yet completely understood, could be an
issue in concentrated areas of previous drilling.
Figure 6: First-Month Avg. Rates, Boepd
Recent Deals/Acreage Values: The Eagle Ford has
seen a flurry of deals over the past year, as companies
have flocked to the play en masse seeking liquids
growth. A total of $7 billion of capital has been used
to JV/purchase ~600,000 net acres from our coverage
list alone, and that does not include some of the deals
that have not been publicly released. A slew of JVs
have helped move acreage values up in Core areas, as
appetite from foreign buyers has been strong. We
estimate a ballpark rate of ~$10,000/acre for good
acreage in the play, but deal prices have been steadily
increasing through 2010/2011.
County
DeWitt
Live Oak
Karnes
Webb
La Salle
Gonzales
McMullen
Dimmit
Atascosa
Frio
Zavala
Maverick
30-day Avg
Boepd
1,210
1,099
764
748
696
608
474
471
300
234
190
75
Source: HPDI, Howard Weil
Infrastructure Situation Limiting, but Improving:
Compared with other nascent shale plays, refining
capacity and transportation infrastructure is advanced
in the south Texas area due to significant regional oil
and gas operations in the past. However, drilling and
production has increased significantly since late 2008,
and we have seen areas of limitation surface, with
some production curtailments due to insufficient
takeaway capacity. There are numerous new or
planned projects to alleviate the issues, and generally,
we view infrastructure as a positive attribute for the
Eagle Ford region with close proximity to refining
capacity and transport hubs.
Economics: We have done our best to differentiate
the Eagle Ford Economic returns into 3 Core
geographic segments. Our analysis shows the highest
returns in the Condensate and volatile (high pressure)
Oil Windows, highlighted in Figure 5 Area #3. Based
on our type curves and economic models described
later in this report, the best locations to date generate
IRRs of >100% in the current commodity
environment.
First-month average production rates are shown by
county in Figure 6, although we note that this data is
somewhat skewed by number of wells drilled and do
not tell the whole story as these rates do not reflect
Figure 5: Comparative Core Regions
Area 3
Area 2
Area 1
Source: HPDI, Howard Weil
Page 3 of 33
Howard Weil
June 1, 2011
Eagle Ford Shale – Not All Areas are Created Equal
Basic Geologic Considerations
The Eagle Ford Shale is an Early Cretaceous age
zone, bounded above by the Austin Chalk and
Anacacho and below by the Buda. Rock and reservoir
quality is on par, if not better, than most other
comparable shale plays. The reservoir is generally
found between 5,000’ and 11,500’ deep with zone
thickness ranging from 140’ to 450’. Commonly, the
reservoir exhibits good porosity and has highpressure indications, especially in the more southern
regions of the play where the formation is deeper and
more gas-saturated. Estimates of OOIP range from 40
to 70 MMBbl per section and OGIP estimates range
from 140 to 150 Bcf per section. In a recent
presentation, Pioneer estimated ~150 Tcfe of gross
resource potential across the play’s ~ 4.5MM acres.
Figure 8: Reservoir Depth
Source: Energy Strategy Partners, February 2011
•
Figure 7 summarizes Eagle Ford shale reservoir
characteristics.
Figure 7: Reservoir Characteristics
Total organic content (TOC)
Log porosity
Permeability (nD)
Pressure gradient (psi/ft)
Water saturation
Anticipated recovery factor - oil
Anticipated recovery factor - wet gas
3-7%
6-9%
700-3,000
0.4-0.7
13-25%
6-10%
30-40%
Source: Chesapeake Analyst Day 2010 Presentation
While operators have already come a long way along
the learning curve since 2008, we expect that industry
technical understanding of the reservoir will increase
significantly in 2011 and beyond. After initial
delineation drilling which has been ongoing since late
2008, companies are now beginning to realize benefit
from previous experimentation with completion
methods and well design. Further, there are ongoing
detailed studies underway, which should help move
the industry further along the technical curve,
including an ongoing multi-company, geoengineering study organized by Core Labs. We find
the following to be the key reservoir-based
determinants of locational value:
•
Depth - Reservoir depth varies considerably
across the play, generally migrating deeper
from northwest to southeast. The depth of the
zone has important economic implications, as it
is a major determinant of reservoir pressure
(and hydrocarbon flow rate) and well cost. The
contour map in Figure 8 shows the depth of the
reservoir across the play with the shallowest
regions in the northwest and getting deeper
downdip to the southeast.
Thickness - The Eagle Ford Shale reservoir
ranges greatly in thickness. There are pockets
within the play where the reservoir grows to
over 400’ thick, which are obviously desirable
locations for operators. The thicker sections of
the zone are easier for operators to drill and
stay within the target formation with the lateral
– generally, the Eagle Ford reservoir is thick
and easy to drill vs. other shale plays. Still,
many operators use steering technology to
make keep the lateral in the optimal placement.
The isopach map in Figure 9 shows general
thickness readings based on available
information. Reservoir thickness is typically
greatest along the Edwards Reef trend.
Figure 9: Reservoir Thickness
Source: EOG
Page 4 of 33
Howard Weil
June 1, 2011
Eagle Ford Shale – Not All Areas are Created Equal
Figure 10: Eagle Ford Lithology vs. Other Shale Plays
Source: Schlumberger, Rosetta
•
Rock Composition - One of the most
appealing features of the Eagle Ford Shale is
the high calcite content (~70%), low clay
content, and brittle nature of the rock, which
makes the artificial fracturing process easier
and more productive. Arguably, the Eagle Ford
play exhibits great rock quality vs. other shale
plays, although rock quality can also be quite
variable from location to location. The organic
composition of the Eagle Ford is shown in
Figure 10, relative to other shale plays.
•
Faulting - Areas of material faulting do occur
within the Eagle Ford play boundaries and
elsewhere in the region, with the most
significant faulting present parallel to the
Ouachita orogenic belt to the northwest.
Notably, the Charlotte-Jourdanton fault zone
stretches from southeast Frio County across
Atascosa County to the western edge of Wilson
County. Additional areas of faulting run from
the southeast corner of Atascosa along the
northernmost extent of both Karnes and Dewitt
counties, with growth faults also prevalent in
northern Webb County.
Figure 11: Notable Geologic Features
Source: USGS: 2003 Geologic Assessment of Undiscovered Conventional Oil and Gas Resources in the Upper Cretaceous Navarro and Taylor Groups,
Western Gulf Province, Texas
Page 5 of 33
Howard Weil
June 1, 2011
•
Gas/Water Saturation – Because the reservoir
is shallower and the lower gravity oil molecules
are larger, the Oil Window typically exhibits
lower
reservoir
pressure
and
lower
corresponding initial flow rates. The pressure
indications generally increase moving south
across the Oil Window and into the Condensate
Window, where the reservoir is more gassaturated, generating greater flow of
condensate/liquids through the shale. In the Oil
Window, high initial water recoveries are likely
an indication of reservoir water saturation,
requiring different fracturing methodology to
create optimal flow. The geographic area
furthest south in the Oil Window has relatively
higher reservoir pressure than the northern Oil
Window, and we refer to this area as the volatile
Oil Window.
Eagle Ford Shale – Not All Areas are Created Equal
see lower relative recoveries from the Eagle Ford
shale zone. Figure 13 shows previous wells drilled
targeting formations other than the Eagle Ford shale.
Figure 13: Drilling History, Eagle Ford Region
Target Formations/Regional Drilling History
Figure 12 map depicts the Eagle Ford shale and
additional formations present in the South Texas
region.
Figure 12: Eagle Ford Stratigraphic Map
Source: El Paso October 2010 Presentation
There is significant drilling history in the Eagle Ford
play region, as multiple zones have previously been
targeted. This has helped to shorten the learning curve
compared to other new shale plays, as vertical well
data and seismic databases are abundant. Notably, the
Austin Chalk and Buda reservoirs have been frequent
targets for wells drilled in the northern section of the
play, spanning from northeastern Dimmit County
through Gonzales County to the northwest. We do not
yet have a full understanding of any reservoir
depletion issues associated with historic drilling, but
the Eagle Ford shale was likely the source rock for
Austin Chalk hydrocarbon recoveries. As such, we
think that areas with significant Chalk drilling could
Source: HPDI, Howard Weil
Economics
Leasing/Deals: Many of the legacy operators in the
play stumbled upon the Eagle Ford while targeting
another zone. For example, one of the industry
leaders, Pioneer Natural Resources, amassed acreage
in the region targeting the Edwards reservoir, and built
a significant 3-D seismic database for that effort,
which was eventually used to better understand the
shallower Eagle Ford. Similarly, Swift Energy leased
acreage now prospective for the Eagle Ford to target
the shallower Olmos formation.
Leases in the Eagle Ford (and S. Texas in general)
have typically been larger than other regions. Average
lease size is 350 net acres, which is 25x the average
Haynesville lease size and ~270x the average Barnett
lease size. Operating leases of this size is generally
easier, requiring less lease maintenance on a per acre
basis and allowing operators to plan their operations
more holistically. Further, since Texas is one of the
most knowledgeable and educated states pertaining to
oil and gas drilling, the regulatory environment is
transparent and generally friendly to industry. Finally,
because the land in the region is rural, the interaction
between oil and gas operations and the population is
less frequent.
As the play has evolved, leases in the Eagle Ford have
become harder to come by, especially larger blocks.
Activity peaked in 2Q10 with an estimated 880,000
Page 6 of 33
Howard Weil
June 1, 2011
Eagle Ford Shale – Not All Areas are Created Equal
acres leased and has since fallen off as land values
increased and acreage became more scarce. Dry Gas
Window leasing has been almost non-existent recently
due to the current commodity environment, and in
2010, the Oil Window saw the most activity as blocks
in the Wet Gas Window were already scarce.
Currently, most of the large contiguous blocks in the
Core areas of the play have been leased, and much of
the activity now involves existing operators tacking on
smaller blocks to increase drilling inventory.
In this commodity environment, the emphasis on
liquids drilling is not surprising. However, in the
Eagle Ford, one “liquids” location could be entirely
different from another. In the north of the play, the
larger oil molecules can be more difficult to extract
than the condensate/NGLs found further south, which
benefit from reservoir gas saturation and higher
pressures. The Condensate Window typically exhibits
the best economic returns, benefitting from the higher
pressure, gas-aided flow rate and liquids price uplift.
Lease expirations will force operators to drill to hold
acreage in the coming quarters as the first wave of
leases will begin to expire in the third and fourth
quarters of 2011 and expirations will ramp up in 2012.
This may present an opportunity for larger operators
to pick up more acreage, as less capitalized companies
may not be able to afford the escalating capital
commitment. However, a flurry of JVs have brought
foreign capital into the play, largely in the form of
drilling carries, which should help sustain major
operations.
NGLs are a significant component of production in
the Condensate/Wet Gas Window of the play, and the
economic returns rely on the products markets. Ethane
is the largest component product of the NGL barrel on
a volume basis (50%+) but is relatively equally
weighted with Propane and Natural Gasoline on a
revenue basis. Because of relative pricing parity for
ethane, some operators choose not to process it and
leave it in the gas stream to receive gas pricing. While
we note the recent concern about NGL pricing as
operators process the liquids to receive premium
pricing vs. natural gas, we have seen strong pricing for
the NGL barrel recently, with realizations near or
above 50% of WTI benchmark, within the historic
range despite the benchmark volatility. In Figure 15,
the chart shows Mont Belvieu NGL pricing as a
percentage of WTI. For purposes of this report, we
assume NGL pricing to be 50% of the benchmark.
Figure 15: NGL Pricing
Buyer
KNOC
CNOOC
Statoil
PXP
PVA
Reliance
GDP
BP
Total
Date
Seller
Announced
APC
3/21/2011
CHK
10/11/2010
Talisman
10/11/2010
Dan Hughes
10/5/2010
Undisclosed
8/12/2010
PXD
6/24/2010
Blackbrush
4/12/2010
Lewis Energy
3/2/2010
Value
($MM)
1,550
2,160
1,325
578
31
1,150
59
175
$7,028
Implied
Acreage
Net Acres Value
80,000
$17,600
200,000 $10,300
97,000
$10,900
60,000
$9,633
6,800
$4,600
95,400
$10,200
35,000
$1,675
40,000
$4,300
614,200 $11,442
$/Bbl
Figure 14: Selected Eagle Ford Transactions
$160.00
80.0%
$140.00
70.0%
$120.00
60.0%
$100.00
50.0%
$80.00
40.0%
$60.00
30.0%
$40.00
20.0%
NGL Bbl Price (% of WTI)
Eagle Ford transactions (Figure 14) have been heating
up as operators have continued to ramp up activity.
The area has seen a number of JVs with foreign
entities looking for US shale exposure and technical
knowledge, in addition to the usual M & A activity.
Recent deals imply valuations of $10,000/acre or
higher for good liquids-rich acreage in the play,
although we suspect some froth is built into the JV
transaction valuations, as the foreign partner’s
motivation for entering the play is not entirely specific
asset return driven.
Source: Howard Weil
Targeting Liquids vs. Gas: It is widely believed that
the Eagle Ford play encompasses three distinct
geographic windows, although this assumption is
misleading as we have found the play to exhibit more
of a gradient rather than different sections with set
borders (as shown on many maps). However, in
general terms, the play does transition from liquids to
dry gas moving downdip, northwest to southeast.
WTIC Benchmark
$20.00
10.0%
NGL Pricing (% WTI)
$0.00
1/25/2008
0.0%
1/25/2009
1/25/2010
1/25/2011
Source: Bloomberg, Howard Weil
Page 7 of 33
Howard Weil
June 1, 2011
IP Rates and EURs: The main purpose of this report
is to identify the economic implications of diverse
acreage positions within the Eagle Ford Shale play.
Production rates obviously vary considerably based on
a group of factors we have discussed previously,
although we typically find higher flow rates and EURs
in the Condensate/Wet Gas Window of the play, as
indicated on the map in Figure 16.
Figure 16: Eagle Ford First-Mo. Avg., Boepd
Eagle Ford Shale – Not All Areas are Created Equal
On a county-by-county basis, first month average
production rates favor the Condensate Window as
well, with high flow rates and liquids production in
Live Oak, Dewitt, Karnes, La Salle, and McMullen
counties. On the oilier side, results in Gonzales come
out in front though do not have the amount of data
points that the other areas do. First-month averages
have also been high in Webb County, although
production has been gassier than other counties. The
bubble chart in Figure 18 shows first-month average
production by county.
Figure 18: Eagle Ford First-Mo. Avg. Rates, by County
Active Eagle Ford Wells (through Feb 2011)
1,600
1,400
DEWITT, 40
30-day Avg (Boepd)
1,200
1,000
LIVE OAK, 16
KARNES, 74
LA SALLE, 107
800
GONZALES, 54
WEBB, 127
600
MCMULLEN, 38
DIMMIT, 105
400
ATASCOSA, 34
FRIO, 8
200
ZAVALA, 7
MAVERICK, 23
Source: HPDI, Howard Weil
0
0%
20%
40%
60%
80%
100%
IP - Avg. % Oil
While the trend of the best drilling results is easily
visible on the previous map, the current commodity
environment favors liquids production as oil pricing
has been very high relative to gas pricing recently.
The map in Figure 17 shows only the liquids portion
of the first month averages for the same wells,
depicting a slight migration of the current economic
Core into the more liquids-rich northern section of the
play.
Figure 17: Eagle Ford First-Mo. Liquids Avg., Bopd
Source: HPDI, Howard Weil
Well Costs/Best Practices: Well costs fluctuate based
on the vertical depth to the Eagle Ford reservoir and
the completion design. As the reservoir gets deeper
from northwest to southeast, the drilling cost for the
vertical leg of the well increases.
As the play has matured, completion design has
evolved, with laterals currently ~5,000’ and frac
intervals ranging from 250’ to 350’ apart. However,
operators continue to experiment with new methods to
both increase recovery and decrease cost. Swift
Energy was one of the first operators to remove the
intermediate well casing string, estimating savings of
close to $1MM per well, and others have followed
SFY’s example. Currently, many operators do not use
the intermediate casing in the regions where the
reservoir is relatively shallow.
Completions have become an increasingly significant
factor in well costs recently, running 50% or higher of
total D&C costs. Service equipment has been in short
supply with the increasing drilling. There is no single
optimal completion method in the Eagle Ford shale as
the reservoir characteristics vary significantly across
the play, and completion design is a moving target in
the Eagle Ford as technology advances. To perforate
Source: HPDI, Howard Weil
Page 8 of 33
Howard Weil
June 1, 2011
the wells, operators can select the sliding sleeve
method to reduce completion time over plug and perf.
Eagle Ford Shale – Not All Areas are Created Equal
Figure 20: Horizontal Rig Count by Play
Eagle Ford/Haynesville Rig Count
250
Many operators are using hybrid fracs, pumping slick
water and fine mesh sand first, followed by a
crosslinked fluid with higher concentrations of larger
mesh proppant. Proppant volume and type both vary
by operator/location and can have a significant impact
on costs. A typical Eagle Ford frac job will pump
300,000 to 400,000 lbs of proppant per stage, and on
average higher proppant density is used in deeper
sections vs. shallower areas.
200
150
100
50
Eagle Ford
Figure 19: HiWAY Frac Results
Haynesville/CV
May-11
Apr-11
Mar-11
Feb-11
Jan-11
Dec-10
Nov-10
Oct-10
Sep-10
Aug-10
Jul-10
Jun-10
0
May-10
One notable new experimental technology is SLB’s
HiWAY frac – a completion method that attempts to
open channels in the rock to allow the hydrocarbons to
flow more easily and thus increase recoveries.
Currently, operators like HK are using the HiWAY
fracs in some of their wells and reporting good initial
results. Figure 19 shows HK’s HiWAY frac results vs.
previous results using hybrid and slickwater fracs.
Report Date
Source: SmithSTATS, Howard Weil
Well spacing has consistently become tighter as
operators have gained further understanding of the
play. The horizontal wells being drilled are estimated
to be draining 80-85 acres, and we think this will
eventually become the norm for spacing, though some
operators may begin testing further downspacing. Pad
drilling and multi-laterals are likely to evolve as best
practices for drilling, allowing operators to save
money on site infrastructure, mobilization times and
day rates from service companies.
Comparative Regional Returns: To analyze the
diverse returns noted across the Eagle Ford play, we
chose 3 geographic regions to represent a large
portion of drilling activity to date, depicted in Figure
21. For each area, we built type curves based on local
operator information, which are included in the
Appendix of this note.
Source: Petrohawk
Figure 21: Eagle Ford Core Economic Regions
Recently, pressure on well costs has increased as the
rig count has exploded. We expect completion cost
inflation to continue to bite into margins across the
play in the near-term as more drilling rigs enter from
dry gas plays seeking liquids exposure. Figure 20
shows the increase in Eagle Ford rig count vs. the dry
gas Haynesville. We think the trend continues as
acreage in the Haynesville becomes HBP’d.
Area 3
Area 2
Area 1
Source: HPDI, Howard Weil
Page 9 of 33
Howard Weil
June 1, 2011
Eagle Ford Shale – Not All Areas are Created Equal
Area 1 - APC, CHK, ROSE, SM
Figure 23: Area 1 Economic Sensitivity
Area 1 Oil Price Sensitivity
Figure 22: Notable Area 1 Well Results
CHK
ROSE
ROSE
SM
SM
SM
County
PGE DOS
1H
Webb
PGE
Browne
1H
Webb
Gates
Ranch
North
Gates
Ranch
South
Galvan
Ranch
10H
Galvan
Ranch
14H
Galvan
Ranch
16H
Webb
Webb
Webb
Webb
Webb
50.0%
40.0%
IRR
CHK
Well
Name
60.0%
30.0%
20.0%
$6MM Well Cost
$7MM Well Cost
10.0%
$8MM Well Cost
0.0%
$70/$5
(1)
$85/$5
$100/$5
Com m odity Price ($ per Bbl/$ per Mcf)
(1)
Area 1 Gas Price Sensitivity
50.0%
(2)
45.0%
40.0%
35.0%
(2)
30.0%
IRR
Operator
24-hr IP
(avg. per
well)
1,045
Bopd +
3,100
Mcfpd
1,200
Bopd +
4,000
Mcfpd
450 Bopd
+ 5,000
Mcfpd
350 Bopd
+ 7,000
Mcfpd
175 Bopd
+ 6,950
Mcfpd
66 Bopd +
6,600
Mcfpd
350 Bopd
+ 6,300
Mcfpd
(2)
Source: Company presentations
(1) Avg. IP rates for ROSE wells drilled through Oct 2010
(2) HW estimate of pre-processing volumes
25.0%
20.0%
15.0%
$6MM Well Cost
10.0%
$7MM Well Cost
$8MM Well Cost
5.0%
0.0%
Area 1 encompasses northern Webb and southern
Dimmit counties. We estimate the average regional
well produces ~40% dry gas per well with the
remaining production split between NGLs and
Condensate. Generally, as you move north in this
region, the liquids production content increases. For
example, APC only produces ~25-30% dry gas from
its wells in south Dimmit County, but other operators
estimate higher gas yields just across the county
border in northern Webb County. To date, wells in the
northern half of Dimmit County are seeing lower
pressure indications and corresponding flow rates, so
we have limited our core region to the southern half of
the county. We estimate average D&C cost of $6-7
MM with avg. 5 Bcfe EURs, although we note the
difficulty in choosing a proxy for such diverse acreage
positions. Based on these assumptions, we estimate
the economic returns (measured by IRR) in the area to
range from ~20% to ~55%.
$85/$4
$85/$5
$85/$6
Com m odity Price ($ per Bbl/$ per Mcf)
Area 2 – HK, SFY, EP, MUR, CRZO
Notable Area 2 Well Results
Figure 24: Notable Area 2 Well Results
Operator
Well
Name
County
HK
STS 2412
#1H
EP
Hixon #1H La Salle
EP
Hixon #4H La Salle
CRZO
Mumme
Ranch
12H
La Salle
La Salle
24-hr IP
(avg. per
well)
251 Bopd
+ 7,600
Mcfpd (1)
728 Bopd
+ 2,859
Mcfpd
765 Bopd
+ 2,100
Mcfpd
1,220
Bopd
(2)
Source: Company presentations
(1) Field discovery well
(2) Flared gas not included
Page 10 of 33
Howard Weil
June 1, 2011
Eagle Ford Shale – Not All Areas are Created Equal
The region we have defined as Area 2 spans across
central La Salle and McMullen counties. The acreage
spans both the Oil Window and Wet Gas Windows,
with the northern section more oily while the southern
section is more gassy. We estimate the well
production profile to include ~65% dry gas, ~25% wet
gas, and the remainder condensate, with average well
costs of ~$8MM. Northern La Salle County has also
produced positive initial well results with higher
condensate contributions, but the flow rates taper off
moving north into Frio County, likely a result of the
shallower depths and lower reservoir pressure and gas
saturation. We estimate average EURs in the region of
close to 6 Bcfe. The economic returns generated in
this region are sensitive to both oil and gas price. In
the current commodity environment, returns are lower
than returns from Area 1 and Area 3, which have
better liquids pricing uplifts, but we believe this is still
a profitable region to spend capital barring a
significant decline in commodity prices. An
improvement in gas prices should have a meaningful
impact for companies in the south of this region.
Area 3 – EOG, COP, PXD, HK, PXP
Figure 26: Notable Area 3 Well Results
Operator
Well Name
County
EOG
HFS Unit (3 wells)
Gonzales
EOG
Hansen - Kullin
#3H
Gonzales
EOG
Dullnig #5H
Karnes
EOG
Beynon Unit (2
wells)
Karnes
EOG
Joseph #3H
Karnes
HK
Krause #1H
DeWitt
HK
Lanik #1H
DeWitt
PXD
Charles Riedesel
DeWitt
COP
Kennedy #1
Karnes
24-hr IP (avg.
per well)
1,403 Bopd +
1,047 Mcfpd
1,538 Bopd +
1,519 Mcfpd
1,353 Bopd +
1,224 Mcfpd
1,424 Bopd +
1,013 Mcfpd
1,317 Bopd +
1,200 Mcfpd
1,150 Bopd +
3,300 Mcfpd
930 Bopd +
2,700 Mcfpd (1)
680 Bopd +
11,600 Mcfpd
1,254 Bopd +
2,358 Mcfpd (2)
Source: Company presentations
(1) Flowed on restricted choke
(2) 30-day average
Figure 25: Area 2 Economic Sensitivity
Area 2 Oil Price Sensitivity
35.0%
30.0%
25.0%
IRR
20.0%
15.0%
10.0%
$7MM Well Cost
$8MM Well Cost
5.0%
$9MM Well Cost
0.0%
$70/$5
$85/$5
$100/$5
Com m odity Price ($ per Bbl/$ per Mcf)
Area 2 Gas Price Sensitivity
40.0%
35.0%
30.0%
Area 3 generates the best average economic returns in
the play in the current commodity environment,
because of a higher liquids contribution vs. the Dry
Gas Window coupled with higher reservoir
pressure/flow rates vs. the more northern parts of the
Oil Window. This region stretches from northeastern
McMullen County through to Gonzales/DeWitt
counties to the northeast. This is where we have seen
some of the highest return wells drilled to date,
including HK’s Black Hawk region, which the
Company recently estimated it will be able to generate
~$27 MM NPV per well at April 2011 strip pricing.
We estimate average well costs in the region of ~$8.5
MM/well and EURs over 6 Bcfe with ~70%
condensate/NGLs. While levered to oil and product
pricing, returns in this region can withstand significant
commodity price deterioration, still generating IRRs
in excess of 45% at $70/Bbl oil. Operators in the area
have proven the acreage as one of the sweet spots of
the Eagle Ford.
IRR
25.0%
20.0%
15.0%
10.0%
$7MM Well Cost
$8MM Well Cost
5.0%
$9MM Well Cost
0.0%
$85/$4
$85/$5
$85/$6
Com m odity Price ($ per Bbl/$ per Mcf)
Page 11 of 33
Howard Weil
June 1, 2011
Eagle Ford Shale – Not All Areas are Created Equal
Figure 28: Condensate
Coast/South Texas
Figure 27: Area 3 Economic Sensitivity
Area 3 Oil Price Sensitivity
Refining
120.0%
100.0%
Plant Location
Texas City
Port Arthur
Corpus Christi
Baytown
Houston
Beaumont
Deer Park
Sweeny
Pasadena
Three Rivers
San Antonio
Gulf Coast/South Texas
Refining Capacity
IRR
80.0%
60.0%
40.0%
$7.5MM Well Cost
$8.5MM Well Cost
20.0%
$9.5MM Well Cost
0.0%
$70/$5
$85/$5
$100/$5
Com m odity Price ($ per Bbl/$ per Mcf)
90.0%
80.0%
70.0%
60.0%
IRR
50.0%
40.0%
30.0%
$7.5MM Well Cost
$8.5MM Well Cost
$9.5MM Well Cost
10.0%
0.0%
$85/$4
Gulf
Current Refining
Capacity
(MBbl/d)
752
709
641
576
358
345
327
247
117
96
12
4,180
Source: SM Energy, March 2011
Area 3 Gas Price Sensitivity
20.0%
Capacity,
$85/$5
$85/$6
Com m odity Price ($ per Bbl/$ per Mcf)
Because production growth from the Eagle Ford has
exceeded forecasts, infrastructure constraints have led
to curtailments in some regions of the play. One
current example is a lack of reliable and consistent gas
takeaway capacity in the westernmost areas of the
Eagle Ford. As drilling activity has increased,
midstream companies have announced a slew of new
projects to increase gathering capacity and provide
new transportation options.
Processing capacity, specifically for the coveted Eagle
Ford NGLs, is also poised to see significant capacity
additions in the next couple of years. The following
facilities depicted in Figure 29 offer NGL
fractionation currently:
Figure 29: NGL Fractionation Capacity
Infrastructure Buildout Coming
One of the primary beneficial attributes of the Eagle
Ford is its geographic proximity to the Gulf Coast
refining system. With 4.2 MMBbls/d of refining
capacity residing along the South Texas Gulf Coast,
Eagle Ford producers will ultimately have a
transportation advantage over other liquids plays that
are located further inland and lack ample processing
infrastructure/capacity. Given the amount of nearby
refining capacity, we believe the key hurdle near-term
is building sufficient transportation/logistics to access
the vast Gulf Coast refining system.
Company
Enterprise
Facility
Location
Gross Capacity (Bbl/d)
Mont Belvieu
Mont Belvieu
Shoup and Armstrong Nueces/DeWitt Counties
325,000
82,000
Cedar Bayou
Gulf Coast
Mont Belvieu
Mont Belvieu
215,000
108,000
MB-1
Mont Belvieu
160,000
Houston Central
Harris County
22,000
Point Comfort
65,000
977,000
Targa
ONEOK
Copano
Formosa
Point Comfort
Total Current Capacity
Source: SM Energy, March 2011
Some of the more meaningful expansion projects
recently completed or on the drawing board include:
• Kinder Morgan/Copano JV – Kinder Morgan
Energy Partners LP and Copano Energy LLC
formed a JV and intend to increase Eagle Fordserving processing capacity by over 1 Bcfe/d, gas
pipeline total gathering system capacity by 1.35
Bcfe/d, NGL pipe capacity by 75,000 Bbls/d, and
Page 12 of 33
Howard Weil
June 1, 2011
Eagle Ford Shale – Not All Areas are Created Equal
fractionation capacity by 98,500 Bbls/d. The JV
partners have already built 34 miles of 24” gas
gathering pipeline in 2010 connecting northern
Webb, Dimmit, La Salle, and McMullen counties
to the existing Kinder line into Houston. This
current gathering system plus a proposed
extension will have capacity of 350 MMcfe/d.
Additionally, the two companies are building 111
miles of new 24”+ gathering pipe, plus 74 miles
of crossover pipe connecting Kinder Morgan’s
Index 50 and Index 127 to Formosa. Existing
producer contracts are in place with Petrohawk,
Abraxas, Pioneer, Riley, SM Energy, Chesapeake,
Anadarko and others. The JV partners will also
build a new 12” NGL pipeline from Houston
Central Complex to Markham NGL Storage and
Formosa’s Point Comfort Complex with 75,000
Bbls/d transport capacity and will expand
fractionation capacity at Houston Central
Complex from 22,000 Bbls/d to 44,000 Bbls/d by
4Q11.
Figure 30: Kinder Morgan/Copano
Infrastructure Network
Eagle
Ford
Figure 31: Enterprise Eagle Ford Infrastructure
Source: Enterprise Products, March 2011
• NuStar/TexStar – In April 2011, NuStar Logistics
and TexStar Midstream Services announced an
initiative to develop a new pipeline system to
transport crude and condensate to Corpus Christi.
TexStar will build the 12” line, which will run 65
miles and have 120 Bopd capacity, providing
access to Atascosa, Frio, La Salle, McMullen, and
Live Oak counties. In addition, NuStar will build
a new storage facility, with expected project
completion in 2Q12.
• Targa Resources Partners LP, in partnership with
DVN and SM, owns Gulf Coast Fractionators.
Together, the group is planning to expand
capacity on one of its NGL fractionation facilities
at Mont Belvieu by 42% to 145,000 Bbls/d.
Source: Copano Energy
• Enterprise – Enterprise has rapidly expanded its
presence in the Eagle Ford since 2009 with the
Maverick Loop and White Kitchen Lateral
projects. On the horizon, the Company is adding a
new 30”/36” gathering pipeline down the fairway
of the play, a new 600 MMcf/d Cryogenic Gas
Processing facility, a new 127-mile NGL pipeline
to Mont Belvieu (90-210 Mbo/d capacity), and a
new 75 Mbo/d NGL Fractionator at Mont Belvieu.
Figure 31 is a map of Enterprise’s current
gas/NGL gathering and processing system with
planned future additions.
• Energy Transfer Partners LP – ETP completed its
Dos Hermanas pipeline in late 2010/early 2011,
providing 400 MMcfe/d capacity. The line
originates in northwest Webb County and
connects to the Company’s Houston Pipeline in
eastern Webb. Further, ETP will also construct the
Chisholm Pipeline spanning from DeWitt County
to the Company’s LaGrange processing plant.
Chisholm’s eventual capacity is expected to reach
300 MMcfe/d.
• Plains All American Pipeline LP is building a
130-mile crude oil and condensate pipeline, a
marine terminal facility, and 1.5 MMBbls of
storage capacity to service increasing Eagle Ford
volumes. The project is slated to come online
4Q12 and will cost $330MM. The project will
have 300 MBopd takeaway capacity, CHK has
committed to a long-term throughput agreement.
• Valero – 3-Rivers refinery is increasing
processing capacity from 30 MBbl/d of Eagle
Ford crude in 1Q11 and to 40 MBbl/d in June and
60 MBbl/d by the end of the year.
Page 13 of 33
Howard Weil
Eagle Ford Operator Index
Anadarko Petroleum Corporation............................................................. 22
BP plc ...................................................................................................... 28
Cabot Oil & Gas ....................................................................................... 27
Carrizo Oil and Gas Corporation.............................................................. 29
Chesapeake Energy Corporation............................................................. 16
Comstock Resources, Inc. ....................................................................... 29
ConocoPhillips ......................................................................................... 21
El Paso E&P ............................................................................................ 23
EOG Resources, Inc. ............................................................................... 15
ExxonMobil Corporation........................................................................... 31
Goodrich Petroleum Corporation ............................................................. 28
Marathon Oil Corporation......................................................................... 31
Murphy Oil Corporation ............................................................................ 20
Newfield Exploration Company ................................................................ 18
Penn Virginia Corporation ........................................................................ 30
Petrohawk Energy Corporation ................................................................ 17
PetroQuest Energy, Inc............................................................................ 30
Pioneer Natural Resources Co. ............................................................... 24
Plains Exploration & Production Company............................................... 27
Rosetta Resources, Inc............................................................................ 26
Royal Dutch Shell Plc .............................................................................. 31
SM Energy Company ............................................................................... 19
Swift Energy Company ............................................................................ 25
Page 14 of 33
June 1, 2011
Eagle Ford Shale –Not All Areas are Created Equal
EOG Resources, Inc. _____________
EOG Operated Eagle Ford Wells, Through 2/11
Operations: In 2011, we expect EOG will run an 18
rig program, focusing its drilling operations in the Oil
Window where the Company achieves rates of return
between 95% and 140%.
EOG has defined two distinct areas of operations: the
Eagle Ford East and the Eagle Ford West. In the
Company’s Eastern acreage, wells target both the
upper and lower Eagle Ford, which provide high
quality, thick pay zones. EOG has achieved Eastern
IP rates of between 800 and 1,500 Bbl/d, plus rich gas
volumes, and per well EURs of 460 MBoe. In the
West, EOG’s wells target the lower Eagle Ford
formation and utilize longer laterals to maximize rates
and recoveries. Western IP rates range between 600
Bbl/d and 800 Bbl/d, plus rich gas volumes, and per
well EURs are expected to be 430 MBoe.
Source: HPDI, Howard Weil
EOG Operated Eagle Rigs, Active 5/4/11
County
GONZALES
KARNES
LA SALLE
WILSON
Hz Rigs
10
6
2
2
EOG estimates that its net play potential is 900
MMBoe and typical well volumes consist of 77% oil,
12% gas and 11% NGLs.
EOG Well Results
Source: SmithSTATS
Despite a somewhat turbulent entry into the Eagle
Ford, well results continue to outperform and have
become the focal point in the Company’s asset
portfolio. EOG has built a premier Eagle Ford acreage
position, focusing leasing efforts on the volatile Oil
Window,
which
exhibits
over-pressured
characteristics that help increase flow rates and
recoveries. In total, EOG maintains a 595,000 net acre
position, the bulk of which (520,000 net acres) lies in
the Oil Window. EOG also maintains 26,000 net acres
in the Wet Gas Window and 49,000 net acres in the
Dry Gas window.
EOG Eagle Ford Acreage
Source: EOG Resources
Strategic Initiatives: While bottlenecks relating to
proppant availability and crude oil takeaway capacity
remain, EOG has taken actions to mitigate the impact
on future production. First, EOG has signaled that the
Company will increase its vertical integration by
incorporating self sourced fracs. While this move will
make EOG less susceptible to the tight services
environment, EOG expects the initiative will also
generate long-term cost savings by reducing well costs
by ~$1MM. Second, to address takeaway capacity, the
Company has entered into midstream agreements,
with infrastructure expected to be in place by mid
2012. In the interim, EOG will utilize rail car
transportation.
Source: EOG Resources
Page 15 of 33
Howard Weil
June 1, 2011
Eagle Ford Shale – Not All Areas are Created Equal
Chesapeake Energy _____________
CHK Operated Eagle Ford Wells, Through 2/11
Operations: In 2H11, CHK intends to accelerate
development of its Eagle Ford acreage and expects to
run 31 rigs by year end 2011. As of April 2011, CHK
had 17 operated rigs in the play. Looking ahead to
2012, CHK expects to further accelerate operations,
planning to exit the year with 40 operated rigs. Results
to date have been encouraging, as CHK has achieved
peak IP rates of 900 Boe/d and 30-day average rates
of 700 Boe/d. CHK’s average per well EUR is ~595
MBoe. Similar to APC, CHK well costs are
approximately $5.5 million.
CHK Estimated Economic Returns
Source: HPDI, Howard Weil
CHK Operated Eagle Ford Rigs, Active 5/4/11
County
DIMMIT
LA SALLE
MCMULLEN
WEBB
ZAVALA
Hz Rigs
5
7
4
1
1
Source: Chesapeake Energy
Source: SmithSTATS
Aiming to transition from gas to liquids, CHK began
leasing in the Eagle Ford in August 2009 and quickly
amassed a 625,000 net acre position. CHK focused its
leasehold acquisition efforts on the oil and wet gas
windows of the play, in areas that CHK believes to
have the optimal combination of thermal maturity and
permeability. Post its joint venture transaction with
CNOOC, CHK presently maintains the second largest
acreage position in the play with 450,000 net acres.
CHK Eagle Ford Acreage
Joint Venture Transaction: On October 10, 2010,
CHK announced that it had entered into a $2.16
billion joint venture transaction (JV) with CNOOC for
200,000 net acres. The purchase price included $1.08
billion in cash and $1.08 billion in the form of a carry,
which is expected to be exhausted by year end 2012.
On a discounted basis, the JV transaction implies a
$10,300 per acre value. The JV assets are located in
Webb, Dimmit, La Salle, Frio, and McMullen
counties. Going forward, CNOOC will have the right
to acquire its 33.3% share of any additional acreage or
infrastructure associated with the Eagle Ford assets.
The JV will provide the capital required to accelerate
CHK’s Eagle Ford program.
Source: Chesapeake Energy
Page 16 of 33
Howard Weil
June 1, 2011
Eagle Ford Shale – Not All Areas are Created Equal
Petrohawk Energy _______________
HK Operated Eagle Ford Wells, Through 2/11
year. Production results from HK’s 35 wells drilled
imply 70% liquids. Based on strip pricing as of April
2011, the Company estimates ~$27 MM/well NPV
and is moving from 8 rigs currently to 10 rigs in
2H11. Well costs are running $8.5 MM/well currently
and without innovation to well and completion design,
we think there may be pressure from cost inflation.
Hawkville – the location where HK drilled its first
Eagle Ford well, the Company maintains 224,000 net
acres at Hawkville (La Salle and McMullen counties).
While not as prolific as Black Hawk, economic
returns are very good in this commodity environment.
Roughly 50% of the acreage is Dry Gas and 50% is
Wet Gas/Condensate. The Company has superior
returns in the more condensate rich areas. Current well
costs are $7.5 MM with 5,500’ laterals, and the
Company is running 5 rigs.
Source: HPDI, Howard Weil
Hawkville Acreage and Avg. Liquids Yield
HK-Operated Eagle Ford Rigs, Active 5/4/11
County
DEWITT
LA SALLE
MCMULLEN
Hz Rigs
9
4
1
Source: SmithSTATS
Petrohawk announced the first commercial success in
the Eagle Ford Shale at Hawkville in late 2008, and
since then, the Company has been a technical leader in
the play, developing new technology to advance the
industry along the new play learning curve. The
Company maintains 3 significant acreage positions:
Petrohawk Eagle Ford Acreage
Source: Petrohawk presentation
Black Hawk – located primarily in DeWitt County,
HK’s ~60,000 net acres at Black Hawk boasts some of
the best drilling results and implied economics in the
play to date. We view this acreage as the core of the
Eagle Ford. Newly announced type curves suggest 6.4
Bcfe EURs with over one-third produced in the first
Source: Petrohawk presentation
Red Hawk – still in the science phase, HK has not yet
figured out how to unlock the returns at Red Hawk.
Located in Zavala County in the Oil Window, the
Company has had mixed results from its first couple
of wells and is currently flowing back a third and
fourth. If we assume current well costs of $5MM and
200 MBo EURs, the acreage is borderline economic –
we currently give no value for HK’s 50,000 net acres
at Red Hawk in our Company valuation and is not a
focus area for the company.
HK continues to experiment with drilling and
completion design and technology to further
maximize results and control costs. The Company is
using hybrid frac technology vs. slickwater to enhance
recoveries, with good success. Further, working with
Schlumberger, HK is now employing HiWAY fracs
on a number of new wells, with results showing a
~30% increase in yield and ~40% increase in pressure.
Page 17 of 33
Howard Weil
June 1, 2011
Eagle Ford Shale – Not All Areas are Created Equal
Newfield Exploration _____________
NFX Operated Eagle Ford Wells, Through 2/11
Source: HPDI, Howard Weil
NFX Operated Eagle Ford Rigs, Active 5/4/11
County
DIMMIT
Hz Rigs
3
Source: SmithSTATS
Initial Assessment: On January 11, 2011, NFX
provided an initial assessment of its Eagle Ford
acreage, which is located primarily in Maverick and
Dimmit counties. NFX drilled eleven wells which
achieved initial IP rates of between 400 and 900 Boe/d
and an average 30-day rate of 400 Boe/d. EURs are
expected to be between 200 and 400 Mboe per well.
Well costs typically range $6-7MM.
Operations: Due to hunting season restrictions,
drilling and completion activities were suspended
from October 2010 to February 2011. Operations have
since resumed and NFX will continue its Eagle Ford
assessment program utilizing 2 to 3 rigs. In its 1Q11
conference call, NFX noted that it has a dedicated frac
crew working to complete an inventory of ~11 wells.
Recent wells were drilled with lateral lengths of 5,000
ft. and were drilled and cased in an average of less
than 10 days. Efficiency gains have reduced drill and
casing costs to less than $2 million per well, however,
completion services average between $4.5 and $5.0
million per well. 2011 capital spending in the Eagle
Ford is expected to be $250 million and NFX will
focus on optimizing completions to increase
production rates and EURs.
The Eagle Ford represents a relatively new play in
NFX’s portfolio and one that we expect to learn more
about in the coming months, as the Company
continues to test its 335,000 net acre position.
NFX Eagle Ford Acreage
Source: Newfield Exploration
Page 18 of 33
Howard Weil
June 1, 2011
Eagle Ford Shale – Not All Areas are Created Equal
SM Energy ______________________
SM Operated Eagle Ford Wells, Through 2/11
Source: HPDI, Howard Weil
SM Operated Eagle Ford Rigs, Active 5/4/11
County
WEBB
Hz Rigs
3
Source: SmithSTATS
SM has a 250,000 net acre position in the Eagle Ford,
which makes the Company the most leveraged public
company to the play on an Acreage to Enterprise
Value basis. SM’s acreage is split between the
Company’s wholly-owned 165,000 net acres (97%
W.I./76% N.R.I.) and the roughly 85,000 net acres
(27% W.I./ 75% N.R.I.) that SM has operated by
Anadarko. SM ended 2010 with 207 BCFE of proved
reserves from the Eagle Ford and ended 1Q11 with
~1/3rd of total Company production from the Eagle
Ford (versus only 7% as of 1Q10).
SM Eagle Ford Acreage
Source: SM Energy presentation
Operated Acreage – largely spread across Webb and
La Salle counties in the Condensate Window of the
play. Roughly 10-15% of SM’s total acreage position
falls in the Dry Gas Window, but the Company is
holding off on exploiting this acreage until gas prices
improve. During 1Q11, SM produced 91.6 MMcfe/d
from its operated Eagle Ford acreage. The Company is
currently running 3 rigs on this acreage, with plans to
add a fourth rig during 2Q11. SM hopes to increase
the number of operated Eagle Ford rigs to 6 by yearend in order to drill 80 gross wells for 2011. The rigs
are currently directed to the more liquids-rich regions
of SM’s operated acreage, and high Btu gas (NGLs)
provide pricing uplift in the current commodity
environment. SM’s average operated well cost is $6.57MM, yields an average IP rate of 4 – 8 MMcfe/d for
a gross EUR of 3 – 6 Bcfe. SM has secured equipment
and services for its operated Eagle Ford acreage
through the end of the year.
Takeaway Capacity – SM has recently entered into
agreements that will expand the takeaway capacity
from its operated acreage to 190 MMcf/d by 2H13 and
470 MMcf/d by 2H14. Currently, SM has 25 – 30
MMcfe/d choked back on its operated acreage due in
part to pipeline issues in the wet gas portions of its
acreage and trucking capacity constraints in the oily
areas. Takeaway capacity will likely be restricted to
below 100 MMcfe/d until June 1, but capacity should
increase to 150 MMcfe/d by July 1. Rosetta has also
been having similar takeaway issues from its nearby
Gates Ranch acreage.
Non-Op JV Acreage – spread across Maverick,
Dimmit, LaSalle and Webb counties in the Oil and
Condensate Windows of the play. SM has a 27%
working interest in 310,000 gross acres as part of an
APC-operated JV. There are currently 9 rigs running
on the acreage, and Anadarko plans to add a tenth
during 2Q11. Anadarko recently announced a $1.55B
JV for its portion of the shared acreage with a
subsidiary of the Korean National Oil Company
(KNOC), implying a $17,600/acre value.
Potential Divestiture – SM is interested in monetizing
or partnering for a portion of its Eagle Ford position in
order to lock in returns from the play. The largest portion
of this acreage would come from SM’s JV acreage, so
the Company would have more direct control over its
capital allocation to the play. The Company estimates
that the southern portion of its acreage in the Wet Gas
Window of the Eagle Ford has returns equal to that of
the oilier areas to the north included in its JV. This is due
to higher volumes and pressures in the Wet Gas Window
of the play partially offsetting the higher margins of the
Oil Window.
Page 19 of 33
Howard Weil
June 1, 2011
Eagle Ford Shale – Not All Areas are Created Equal
Murphy Oil ______________________
MUR Operated Eagle Ford Wells, Through 2/11
Source: HPDI, Howard Weil
MUR Operated Eagle Ford Rigs, Active 5/4/11
County
DIMMIT
KARNES
MCMULLEN
Hz Rigs
1
2
1
Source: SmithSTATS
An early entrant into the play, Murphy currently has
~220,000 net acres in South Texas that are prospective
for the Eagle Ford and continues to search for more.
The Company’s current acreage is predominantly
spread across Karnes, Atascosa, McMullen, La Salle
and Dimmit counties. MUR’s acreage is prospective
for all three hydrocarbon windows in the Eagle Ford
and is bucketed into four fields—Karnes, Tilden,
Catarina and Nueces.
MUR Eagle Ford Acreage
crews to reduce its backlog. The crew completed 6
wells during 1Q11 and is currently averaging 3-5
completions per month. Murphy estimates its average
drilling cost is $3.5 – 4MM per well with completion
costs running $4 – 5MM. The Company estimates 911 Mboe/d production from the Eagle Ford by YE11,
although takeaway capacity may stagger that growth
temporarily.
Karnes – Murphy’s Karnes Field is named for the
county in which the vast majority of the field’s
acreage resides (with the small residual spread
between Wilson and Bee Counties). Karnes Field is
MUR’s only sanctioned project in the Eagle Ford
currently. The Company holds 14,400 net acres
(19,200 acres with a 75% W.I) or 240 drilling
locations on 80-acre spacing. The acreage in Karnes is
prospective for the Eagle Ford’s Condensate Window,
and the Company estimates EURs of 580 MBoe with
an estimated 86% liquids. Recent production results
have consistently outperformed the current type curve,
and the Company believes restricting flow rates could
drive higher EURs. MUR could produce 4,000 Boepd
without takeaway curtailments, as of May 2011. The
Company estimates it can reach 4,500 Boepd
production by end 2011 with success in ameliorating
its takeaway issues.
Tilden – Similar to Karnes Field, MUR’s Tilden Field
is prospective for the Eagle Ford’s Condensate
Window. At Tilden, Murphy has ~73,400 net acres
(78,900 gross with a 93% W.I.) or 985 drilling
locations on 80-acre spacing across Atacosa,
McMullen and eastern LaSalle Counties. Like Karnes
Field, the Company’s EUR is 580 MBoe, also with an
estimated ~86% liquids-weighting. The Company
intends to begin production in August 2011.
Catarina – MUR’s Catarina Field is located entirely
in Dimmit County and consists of 46,200 acres (100%
W.I.) prospective for the Eagle Ford’s Oil and
Condensate Windows. The Catarina Field has a
drilling inventory of 580 locations on 80-acre spacing.
As of its Analyst Meeting in May 2011, MUR had
drilled 5 wells at Catarina, 3 of which had been
completed. Murphy uses an EUR of 355 MBoe for the
Field, ~59% of which is liquids.
Source: Murphy presentation
MUR currently has 4 operated rigs running in the
Eagle Ford and plans to ramp up to 8 rigs this year. As
of its May 10 Analyst Day, the Company had drilled
25 horizontal wells in the play with 15 online and
another 10 WOC. MUR employs 1.5 dedicated frac
Nueces – The Company’s Neuces Field is largely
prospective for the Eagle Ford’s Dry Gas Window,
and the Company is only drilling to hold acreage. The
Field consists of ~86,000 net acres (92% W.I.).
Murphy has drilled 6 wells at Neuces, completing 5 of
them. Neuces is split between the southern portions of
LaSalle and McMullen counties.
Page 20 of 33
Howard Weil
June 1, 2011
Eagle Ford Shale – Not All Areas are Created Equal
ConocoPhillips __________________
COP Operated Eagle Ford Wells, Through 2/11
Source: HPDI, Howard Weil
COP Operated Eagle Ford Rigs, Active 5/4/11
County
KARNES
LIVE OAK
Hz Rigs
7
5
COP drilled 41 wells in the Eagle Ford in 2010, a
combination of development drilling and drilling to
delineate the geographic extent and resource potential
of its acreage. As of the Company’s 1Q11 Earnings
Call, COP was producing ~20 Mboe/d from 50+ net
wells with ~5 MBoe/d curtailed. The Company has 3
dedicated frac crews and 13 operated rigs, up from 11
rigs during 4Q10. COP plans to drill ~144 wells in the
Eagle Ford in 2011 with a capital budget of $1.4
billion.
During 2011, COP expects to average ~30 MBoe/d
with a nearly 75% liquids weighting. Further, the
Company expects to ramp up production to ~65
MBoe/d over the next couple of years as COP builds
out the pipe infrastructure to provide sufficient
takeaway capacity. COP’s wells-to-date have
outperformed company expectations, with high IP
rates and a 71% liquids-weighting during 1Q11.
During 2010, these wells yielded a cash margin of
$45/Bbl, which compares favorably versus the
$31/Bbl average for the rest of COP’s liquids-rich
U.S. assets and is twice the average of the rest of
COP’s global portfolio.
Source: SmithSTATS
As an early mover in the Eagle Ford through the
acquisition of Burlington in ‘06, COP has a position
of ~240,000 net acres at a cost of ~$350/acre. With
the core of COP’s acreage in the play’s liquids
fairway, the Company has seen recent offers for
comparable acreage of ~$14,000/acre. COP’s acreage
is predominantly located in the Eagle Ford’s
condensate window, stretching from Northeast
McMullen County, through Karnes, De Witt, Lavaca,
Colorado and Fayette Counties and into Northwestern
Austin County.
COP Initial Eagle Ford Well Results
COP Eagle Ford Acreage
Source: Conoco presentation
Source: Conoco presentation
Page 21 of 33
Howard Weil
June 1, 2011
Eagle Ford Shale – Not All Areas are Created Equal
Anadarko Petroleum _____________
APC Operated Eagle Ford Wells, Through 2/11
Operations: In 2011, APC intends to operate a 10+
rig program and aims to drill over 200 wells. To date,
APC has achieved IP rates of ~1,000 Boe/d and
average EURs of 450+ MBoe. Relatively low well
costs of between $5.0 and $5.5 million further
enhance returns, allowing APC to achieve rates of
return in excess of 100%. Hydrocarbon volumes
consist of 46% crude, 27% NGL and 27% gas.
Differentiation: In addition to solid well results and
drilling efficiencies, APC has secured dedicated
service provider agreements and has the necessary
infrastructure in place, allowing APC to efficiently
and effectively develop its acreage and bring
production volumes to sales.
APC Drilling Efficiency
Source: HPDI, Howard Weil
APC Operated Eagle Ford Rigs, Active 5/4/11
County
DIMMIT
MAVERICK
WEBB
Hz Rigs
6
1
2
Source: SmithSTATS
Often considered a premier independent offshore E&P
operator, APC’s onshore US asset base provides the
Company with tremendous growth opportunities.
Specifically, in the Eagle Ford, APC maintains a
200,000 net acre position, concentrated primarily in
the Oil and Condensate-rich Window of southern
Maverick, Dimmit and northern Webb counties.
APC Eagle Ford Acreage
Source: James K. Dodson Company
Joint Venture Transaction: Highlighting the
significant potential of the Company’s acreage
position is the recent $1.6 billion joint venture (JV)
transaction with Korea National Oil Company
(KNOC). On February 21, 2011, APC announced that
KNOC would invest $1.6 billion to earn 80,000 net
Eagle Ford acres and 16,000 net Pearsall acres. The
investment would be made entirely in the form of a
carry, in which KNOC will fund 100% of the capital
costs for the remainder of 2011 and 90% of costs
thereafter, until the carry is exhausted, which we
expect to occur prior to year end 2013.
Similar to CHK’s JV with CNOOC, we continue to
see interest in Eagle Ford assets by foreign oil and gas
companies. APC’s JV with KNOC implies a
discounted value of ~$17,600 per Eagle Ford, which
to date marks the highest per acre valuation in the
play.
Source: Anadarko presentation
Page 22 of 33
Howard Weil
June 1, 2011
Eagle Ford Shale – Not All Areas are Created Equal
El Paso E&P ____________________
EP Operated Eagle Ford Wells, Through 2/11
Ford position, and EP has moved into development
mode running 3-4 rigs, testing 80-acre downspacing
(on 120s currently), and building out infrastructure.
EP Drilling Results to Date
Source: El Paso presentation
Source: HPDI, Howard Weil
EP Operated Eagle Ford Rigs, Active 5/4/11
County
LA SALLE
Hz Rigs
3
Source: SmithSTATS
EP’s ~170,000 net acres in the Eagle Ford span
geographically from the Oil Window in Frio and
Atascosa counties to the north down to the Dry Gas
Window in Webb County, with an estimated 60% of
the acreage in liquids-rich areas. The Company also
has a significant position in the Condensate Window
mainly in central La Salle County. As of early May
2011, EP had completed 26 wells with another 11
wells drilled and WOC. The Company estimates it has
a total of ~1,000 drillable locations in the play.
EP Acreage Map
EP is now beginning to test its acreage to the north
and south of its central La Salle Core position. To
date, the Company has drilled pilot wells in Frio and
Atascosa counties and continues to focus on assessing
the acreage at this time. On its more southern gassy
Eagle Ford acreage, EP is drilling to hold its position
and retain the flexibility to turn on the gas if
commodity pricing improves.
In terms of drilling design, EP typically uses ~5,000’
laterals with 14-18 frac stages. The Company utilizes
wellbore steering technology to help keep the lateral
in zone and has concentrated on improving drilling
efficiency and keeping drilling days to a minimum. A
typical frac includes 350,000-380,000 lbs of proppant
per stage using resin-coated sand in the higher
reservoir pressure locations and white sand for other
locations.
EP Well Design
Source: El Paso presentation
From its central La Salle County acreage, El Paso is
generating high 1,350 Btu gas with wells typically
coming online around 1,000 Boepd with an estimated
75% of recoverable reserves coming from oil. EP has
drilled 34 wells and completed 24 with 12 wells
producing from this region. This acreage represents
the most derisked portion of the Company’s Eagle
Source: El Paso presentation
EP recently completed due diligence on a possible JV
transaction in the Eagle Ford after receiving interest
from multiple parties, but the Company has decided to
develop the acreage alone to retain the economic
returns and control over the pace of the development
program.
Page 23 of 33
Howard Weil
June 1, 2011
Eagle Ford Shale – Not All Areas are Created Equal
Pioneer Natural Resources ________
PXD Operated Eagle Ford Wells, Though 2/11
including $266MM upfront cash and an $879MM
drilling carry for 45% of its 212,000 net acres in the
play. The Company is spending $110MM this year net
of the JV drilling carry. PXD continues to operate the
JV acreage, running 9 rigs currently and going to 16 in
2013. Current well costs are $7-8MM. At the end of
1Q11, PXD had drilled 50 wells and completed 32,
with 24 wells producing.
The Company’s typical well design includes a 5,500’
lateral and 15 frac stages. PXD uses mainly ceramic
but is experimenting with white sand in regions where
the reservoir is shallower and has less pressure. The
Company successfully moved from slickwater to
hybrid fracs pumping ~4MM lbs of proppant and
continues to work to find optimal cluster spacing. In
the future, PXD will likely test channel fracs.
PXD Standard Well Design
Source: HPDI, Howard Weil
PXD Operated Eagle Ford Rigs, Active 5/4/11
County
DEWITT
KARNES
LIVE OAK
MCMULLEN
Hz Rigs
4
2
1
1
Source: SmithSTATS
PXD was an early entrant into the Eagle Ford play, as
the Company originally targeted the Edwards
formation. Pioneer’s acreage lies primarily in the
Condensate Window running northeast from
McMullen to DeWitt and Gonzales counties. The
Company has 24 MMBoe of proved reserves from the
play with an estimated 700 MMBoe of resource
potential and ~2,000 drilling locations. Only ~20% of
the Company’s acreage is located in the Dry Gas
Window with the remaining 80% in the Condensate
Window with varying levels of liquids as shown in the
following graphic.
PXD Eagle Acreage Breakdown
Source: Pioneer presentation
PXD is currently building out midstream
infrastructure with its JV partner, with 5 Central
Gathering Plants (CGPs) currently completed and 7
more planned by 2013. Additionally, the Company
intends to build 749 miles of gathering pipe around its
acreage. PXD’s estimated midstream capital
commitment is $350MM through 2013. PXD has also
made strides to vertically integrate, building out its
own frac crews to decrease the reliance on third party
services. The Company has 1 company-owned frac
fleet in service currently with a second scheduled to
come online in 4Q11. PXD estimates ~$2MM savings
per well, and each frac fleet will pay out in ~12
months (~$45MM capital cost). Owning the frac fleets
allows PXD to continue to execute its program
without being entirely beholden to the services
companies.
Source: Pioneer presentation
Pioneer consummated a JV with Reliance Industries
of India in June 2010, receiving over $10,000/acre
Page 24 of 33
Howard Weil
June 1, 2011
Eagle Ford Shale – Not All Areas are Created Equal
Swift Energy ____________________
SFY Operated Eagle Ford Wells, Through 2/11
Source: HPDI, Howard Weil
SFY Operated Eagle Ford Rigs, Active 5/4/11
County
MCMULLEN
Hz Rigs
4
Source: SmithSTATS
Swift Energy has 79,000 acres are spread across
McMullen (~53,000), La Salle (~14,000), Webb
(~8,000), and Zavala (~4,000) counties. The
Company’s legacy acreage was originally acquired to
target the Olmos formation, and Swift has acreage
prospective for the Oil, Condensate, and Dry Gas
Windows.
SFY Eagle Ford Hydrocarbon Mix
Source: Swift Energy presentation
Oil Window – Swift has ~24,000 net acres that target
the oily portion of the play - ~4,000 in Zavala County
and ~20,000 in McMullen County - providing the
Company with ~300 drilling locations (assuming 80acre spacing) and an estimated 61 – 92 MMBoe of
unrisked resource potential.
High-GOR Oil Window – Swift has another ~20,000
net acres - ~6,000 in McMullen County and ~14,000
in LaSalle County - targeting the high Gas-Oil Ratio
(GOR) Oil Window of the Eagle Ford. The 6,000 net
acres in McMullen County prospective for the high
GOR oil window are from a JV that Swift has with
another operator, Petrohawk. This JV also includes
7,000 acres prospective for the Eagle Ford’s Dry Gas
Window. In total, Swift’s interest in the JV provides
the Company with ~162 drilling locations and 0.6 –
1.1. Tcfe of net unrisked resource potential. Apart
from the JV, Swift has 14,000 high GOR Oil Window
acres in LaSalle County that encompass the
Company’s Artesia wells and provide the Company
with ~175 drilling locations and 44 – 66 MMBoe of
total net unrisked resource potential.
Dry Gas Window – Away from the aforementioned
JV, Swift has ~28,000 operated Eagle Ford acres in
the Dry Gas Window. Roughly 20,000 of these acres
are located in southern McMullen County and offer
Swift ~250 drilling locations and 1.0 – 1.8 Tcfe of net
unrisked resource potential. The other 8,000 acres are
located in Webb County and encompass Swift’s
Fasken Ranch leases, which could provide the
Company with another ~100 drilling locations and 0.4
– 0.7 Tcfe of total net unrisked resources.
Future Development Plans – From 2011 – 2013,
Swift plans to drill ~95 Eagle Ford wells, including 26
in the Oil Window, 43 in the high GOR Oil Window
and 26 in the Dry Gas Window. On March 8th, Swift
entered into an agreement with Southcross Energy to
construct a new pipeline to Swift’s McMullen County
acreage. Swift expects the pipeline to provide the
Company with up to 90 MMcfe/d firm capacity
starting in 2H11. Swift does not anticipate having any
takeaway capacity issues during the next several
years.
Extending Laterals – Originally, Swift was using
4,000’ laterals for its South Texas wells with
approximately 12 frac stages spaced 300’ apart at a
total well cost of ~$7MM. Using this model, each
liquids-rich location offered an estimated resource
potential of greater than 250 MBoe and each dry gas
location offered upwards of 5 Bcfe of resource
potential. However, Swift has determined that the
Company can further optimize the economics of its
Eagle Ford wells by employing 6,000’ laterals. While
the 6,000’ lateral wells cost closer to $9MM, the
6,000’ model employs 17 frac stages at 350’ spacing
and returns greater than 350 MBoe for each liquidsrich wells and upwards of 7 Bcfe for each dry gas
well, thus offering a greater rate of return.
Page 25 of 33
Howard Weil
June 1, 2011
Eagle Ford Shale – Not All Areas are Created Equal
Rosetta Resources _______________
ROSE Operated Eagle Ford Wells, Through 2/11
Outside of Gates Ranch, ROSE’s acreage, which is
largely untested, includes blocks in central Dimmit
County, Gonzales County, and northeast La Salle
County. We think the untested regions look to be in
good zip codes, and could drive valuations higher for
the Company as they are derisked/delineated. ROSE
recently announced that it is adding a 3rd Eagle Ford
rig to drill pilot wells on untested acreage this year,
and results should come in 2H11.
ROSE Acreage Breakdown
Source: HPDI, Howard Weil
ROSE Operated Eagle Ford Rigs, Active 5/4/11
County
WEBB
Hz Rigs
2
Source: SmithSTATS
ROSE has ~65,000 net acres in 6 different Eagle Ford
regions. The Company has concentrated its drilling to
date in northern Webb County at Gates Ranch where
it has ~26,500 net acres. Results from Gates Ranch
have been some of the best in the play to date with a
post-processing EUR of 7.2 Bcfe and current well
costs of $7.5-8.5MM. Further, drilling results are
coming in ahead of the Company’s type curve, and we
would not be surprised to see the EUR move higher in
the coming months. Further, ROSE will be testing
downspacing in 2H11. The Company is scheduled to
have 58 wells drilled by YE 2011, which represents
~25% of its Gates Ranch locations at current spacing
assumptions.
Gates Ranch Well Results
Source: Rosetta presentation
Takeaway capacity has become an issue at Gates
Ranch and other northern Webb County locations as
drilling has accelerated rapidly (120 MMcfe/d in May
2011 after only 18 months). ROSE has faced
curtailments even with firm takeaway contracted as
production growth has exceeded expectations, and the
Company continues to try to increase capacity through
any means available.
In addition to pipe capacity, oil trucking capacity is
also a pressure point currently in South Texas. To
mitigate potential disruptions, ROSE has developed a
project to move condensate by pipe to a truck terminal
in Catarina, Texas, and is also looking at other
potential transportation options including rail and
barge.
Moving forward, ROSE continues to concentrate on
drilling efficiency with recent Gates Ranch wells
averaging 15 days from spud to rig release. The
Company is beginning to use pad drilling which
shows positive initial results, having completed a 3well pad in only 8 days. On the completion side, the
Company is pumping 4MM lbs of proppant per well
and thinks pad drilling may reduce costs by
$500,000/well. We think the Company has proven to
be one of the better operators in the play so far, and
we would not be surprised to see ROSE generate
similarly positive value from its untested positions.
Source: Rosetta presentation
Page 26 of 33
Howard Weil
June 1, 2011
Eagle Ford Shale – Not All Areas are Created Equal
Cabot Oil & Gas _________________
Plains Exploration ________________
COG Operated Eagle Ford Wells, Through 2/11
PXP Operated Eagle Ford Wells, Through 2/11
Source: HPDI, Howard Weil
Source: HPDI, Howard Weil
COG Operated Eagle Ford Rigs, Active 5/4/11
PXP Operated Eagle Ford Rigs, Active 5/4/11
County
FRIO
County
KARNES
Hz Rigs
1
Hz Rigs
5
Source: SmithSTATS
Source: SmithSTATS
The Eagle Ford will serve as the new core of COG’s
Southern operating division. COG currently maintains
approximately 60,000 net acres in the oil window of
the Eagle Ford, with acreage concentrated in Zavala,
Frio, La Salle and Atascosa counties.
PXP entered the Eagle Ford play in October 2010,
paying $578MM to acquire 60,000 net acres in Karnes
County from private operator Dan Hughes. Roughly
20,000 net acres of the acquisition are within a joint
operating area with EOG. The Company inherited 2
operated rigs and has ramped up to 5 operated rigs, a
quick acceleration into the play. PXP has announced a
couple of good wells, and we expect a slew of
additional results in the next couple quarters. We think
the acreage lies within the Core liquids-rich area of
the Eagle Ford and expect good well results from the
Company. This asset has quickly become a major
focal point for PXP as the Company looks to grow its
onshore portfolio.
COG Eagle Ford Acreage
Source: Cabot Oil & Gas
Operations: COG’s activity to date has focused on
opportunities in the Company’s Buckhorn project,
located in southern Frio and northern La Salle
Counties. To date, COG has drilled 6 operated wells
which have achieved inconsistent and somewhat
disappointing IPs that have ranged from 345 Boe/d to
1,042 Boe/d. COG estimates per well EUR’s of
between 375 and 600 MBoe. In 2011, COG aims to
drill between 25 and 30 net wells, at an average cost
of $7.0 to $8.5 million per well. COG estimates its
resource potential in the Eagle Ford to be between 150
MMBoe and 300 MMBoe. The Company has three
additional wells in its Buckhorn acreage awaiting
completion and three additional non-operated wells
that have been drilled in the 18,000 net acre AMI with
EOG.
The Eagle Ford formation is found 9,500’ to 11,500’
deep on PXP’s acreage, which is proximate to EOG,
MUR, and COP. While it is still early and we do not
have a lot of data, PXP estimates 170 MMBoe of
resource potential and 480 MBoe EURs with ~$7MM
per well costs. If things go according to plan, the
Company could be at 10 Mboe/d by year end and up
to ~15 Mboe/d in 2012. However, the Company’s
WOC backlog has grown quickly as well, standing at
18 wells WOC or waiting connection in early May,
and we would like to see the Company move to secure
completions in the future.
Page 27 of 33
Howard Weil
June 1, 2011
Eagle Ford Shale – Not All Areas are Created Equal
Goodrich Petroleum ______________
BP plc __________________________
GDP Operated Eagle Ford Wells, Through 2/11
BP/Lewis Operated Eagle Ford Wells, Through 2/11
Source: HPDI, Howard Weil
Source: HPDI, Howard Weil
GDP Operated Eagle Ford Rigs, Active 5/4/11
County
LA SALLE
Hz Rigs
2
Source: SmithSTATS
Goodrich acquired Blackbrush’s acreage in April
2010 for $1,675/acre. The acreage is located roughly
50% in northern La Salle County and 50% in southern
Frio County. To date, GDP has announced 9 Eagle
Ford well results. The results from the southern
portion of the Company’s acreage have been more
consistent coming on 600-1,000 Bopd, and very oily.
To the north, the Company has had mixed but
improving results on its first three wells. After the
results to date from the lower half of its acreage, we
expect the Company to move into development mode
and the ~200 locations should be enough to keep a
couple of rigs running full-steam in the near-term. We
give minimal credit currently for the 50% of GDP’s
acreage in Frio County and view this as an upside
option if the Company cracks the code.
GDP Eagle Ford Acreage
BP/Lewis Operated Eagle Ford Rigs, Active 5/4/11
County
LA SALLE
WEBB
Hz Rigs
1
7
Source: SmithSTATS
BP entered the Eagle Ford in March 2010 by forming
a JV with privately-held Lewis Petroleum. In the deal,
BP acquired a 50% working interest in 80,000 acres
spread largely among Webb County and southern
Dimmit and LaSalle Counties, for $160 million or
~$4,000 – 4,500 per acre. While details for the
acreage are scarce, the Eagle Ford interest represents
~5 Tcf of unrisked resource potential for BP. At the
time of the deal, Lewis was only operating a single
rig, but the JV ended 2010 with 4+ rigs drilling the
acreage and has now expanded to 8, with the bulk of
the activity currently focused in Webb County.
Historically, Lewis has been in the region for 20
years, primarily targeting the Olmos formation. At the
time the two companies entered into the JV, Lewis
had filed for more lease permits in 2010—26—than
any other company. In 2002, Lewis drilled and
completed the first well in the Eagle Ford formation.
The southern portions of the JV acreage are
prospective for the Dry Gas Window of the play,
while the northern areas fall in the Condensate
Window and are prospective for a mix of wet and dry
gas.
Source: Goodrich Petroleum presentation
Page 28 of 33
Howard Weil
June 1, 2011
Eagle Ford Shale – Not All Areas are Created Equal
Carrizo Oil and Gas ______________
Comstock Resources _____________
CRZO Operated Eagle Ford Wells, Through 2/11
CRK Operated Eagle Ford Wells, Through 2/11
Source: HPDI, Howard Weil
Source: HPDI, Howard Weil
CRZO Operated Eagle Ford Rigs, Active 5/4/11
CRK Operated Eagle Ford Rigs, Active 5/4/11
County
LA SALLE
County
MCMULLEN
Hz Rigs
1
Hz Rigs
1
Source: SmithSTATS
Source: SmithSTATS
Carrizo’s Eagle Ford acreage is primarily located in
La Salle County, and after the Company’s recent
addition of 8,000 acres, CRZO now holds a total of
~28,000 net acres. Results to date have been positive
with average 24-hr IP rates ~1,000 Boepd with high
liquids content, and it looks like CRZO has leased in a
sweet spot. CRZO is drilling 5,000’ lateral wells with
18 frac stages for $6-7MM and thinks the average
well will produce 70% condensate and 30% wet gas.
The Company is adding a 2nd rig in June 2011 and a
third in December to ramp up production.
CRK has 18,000 net acres in the Eagle Ford play, with
blocks in Atascosa, McMullen, and Karnes counties.
The Company has released 7 wells with improving
results recently. We are most encouraged by the
potential of the ~7,000 acre block in central
McMullen County, but also note that wells in northern
McMullen and Atascosa have held up well over time,
despite lower initial flow rates. CRK is also looking to
add inventory in the play and may also look to
increase its exposure in McMullen County by trading
some of its other existing acreage.
CRZO Eagle Ford Acreage
CRK Eagle Ford Acreage
Source: CRK presentation
Source: Carrizo presentation
Page 29 of 33
Howard Weil
June 1, 2011
Eagle Ford Shale – Not All Areas are Created Equal
Penn Virginia ____________________
PetroQuest Energy _______________
PVA Operated Eagle Ford Wells, Through 2/11
PQ Well Locations
Source: PetroQuest presentation
PQ Operated Eagle Ford Rigs, Active 5/4/11
Source: HPDI, Howard Weil
PVA Operated Eagle Ford Rigs, Active 5/4/11
County
GONZALES
Hz Rigs
3
Source: SmithSTATS
PVA entered the Eagle Ford in August 2011 with a
6,800 acre acquisition in eastern Gonzales County for
$4,600/acre. The Company has announced one well
result at 1,250 Boepd including 1,100 Bopd and high
Btu gas. Other operators such as MHR and EOG have
had success in the region, and PVA is already up to 3
rigs running, which is a good sign that the Company
likes what it sees. Since the initial acquisition, PVA
has added ~6,000 acres, giving the Company a total of
~12,700 net acres and the needed inventory to ramp
up activity. We expect PVA to release 2 or more new
well results in the coming weeks.
PVA Eagle Ford Acreage
County
DIMMIT
Hz Rigs
1
Source: SmithSTATS
While PetroQuest currently has a modest acreage
position in the Eagle Ford (roughly 1,600 net acres),
the Company is aggressively pursuing opportunities to
expand that position and expects to acquire additional
acreage during 2011. The terms of PQ’s agreement
with its JV partner, NextEra, provide PQ with
additional incentive to add acreage as NextEra is
responsible for 75% of the leasehold costs in the Eagle
Ford, in exchange for a 50% working interest. PQ’s
acreage is split between Dimmit (~600 net acres) and
LaSalle (~1,000 net acres) counties and predominantly
falls in the play’s Condensate Window. PQ will be the
operator for a planned three well pilot program in ‘11,
the first of which is located in Dimmit County, with
the following two wells to be drilled on the LaSalle
County acreage. PQ has a 50% working interest in all
three wells in its 2011 program.
As of the Company’s 1Q11 call, PQ had reached TD
and set casing at its initial well, with completion
operations expected during 2Q11. The well was
drilled to a vertical depth of 6500’, and PQ anticipates
all-in well costs of just over $6MM. PQ spud its
second operated well earlier this month. The
Company expects this second well to be drilled to a
deeper TVD of 7500’ and cost a little more than
$7MM. Finally, the Company anticipates that its third
well will test a longer lateral and cost ~$8MM. All in,
PQ expects to spend roughly $14MM of the
Company’s approximately $115MM 2011 CAPEX
budget on its Eagle Ford position.
Source: Penn Virginia presentation
Page 30 of 33
Howard Weil
June 1, 2011
Eagle Ford Shale – Not All Areas are Created Equal
ExxonMobil _____________________
Marathon Oil ____________________
XOM Operated Eagle Ford Wells, Through 2/11
MRO Operated Eagle Ford Wells, Through 2/11
Source: HPDI, Howard Weil
Source: HPDI, Howard Weil
XOM Operated Eagle Ford Rigs, Active 5/4/11
MRO Operated Eagle Ford Rigs, Active 5/4/11
County
MCMULLEN
WEBB
County
WILSON
Hz Rigs
1
1
Hz Rigs
1
Source: SmithSTATS
Source: SmithSTATS
XOM entered the Eagle Ford Shale through their
acquisition of XTO and the Company is in the process
of delineating their 120k net acres. They have 2 rigs
running in McMullen and Webb counties and drilled
15 wells in 2010 in the Wet Gas and Oil Windows of
the play.
Royal Dutch Shell Plc _____________
RDS Eagle Ford Rigs, Active 5/4/11
County
DIMMIT
WEBB
In November 2010, MRO entered the Eagle Ford by
structuring an agreement with Denali Oil & Gas
whereby MRO would pay drilling costs to earn 17,000
net acres along with an option to purchase an
additional 58,000 net acres. Since then, the Company
has increased outright holdings to 59,000 net acres
with rights to acquire an additional 61,000 net acres.
The Denali acreage is located in Wilson and Atascosa
counties, while the specifics of recently acquired
acreage have not been disclosed. MRO spud its first
Eagle Ford well in 1Q11 so we have no results at this
time.
Hz Rigs
1
2
Source: SmithSTATS
RDS entered the Eagle Ford through their acquisition
of East Resources on May 28, 2010. This acquisition
provided them with 250,000 net acres in the liquids
rich window of the play. According to public rig data,
Shell is running 3 rigs in the play in Webb and
Dimmit counties and also has acreage in Maverick
County to the west.
Page 31 of 33
Howard Weil
June 1, 2011
Eagle Ford Shale – Not All Areas are Created Equal
Appendix A - Type Curves
Area 1
7,000
4
6,000
3.5
3
5,000
2
Bcfe
Mcfepd
2.5
4,000
3,000
1.5
2,000
1
1,000
0.5
0
0
1
9
17 25 33 41 49 57 65 73 81 89 97 105 113
Months on Production
9,000
4.5
8,000
4
7,000
3.5
6,000
3
5,000
2.5
4,000
2
3,000
1.5
2,000
1
1,000
0.5
0
Bcfe
Mcfepd
Area 2
0
1
9
17 25 33 41 49 57 65 73 81 89 97 105 113
Months on Production
Area 3
12,000
5
4.5
10,000
4
3.5
8,000
6,000
2.5
Bcfe
Mcfepd
3
2
4,000
1.5
1
2,000
0.5
0
0
1
9
17 25 33 41 49 57 65 73 81 89 97 105 113
Months on Production
Page 32 of 33
Howard Weil
Analyst Certification
We, David Amoss, Blaise Angelico, Joseph Bachmann, Brian Corales, and Peter Kissel, certify that the views expressed in
this research report accurately reflect our personal views about the subject securities or issuers; and we, David Amoss,
Blaise Angelico, Joseph Bachmann, Brian Corales, and Peter Kissel, certify that no part of our compensation was, is, or will
be directly or indirectly related to the specific recommendation or views contained in this research report.
Important Disclosures
This report was prepared for general circulation and does not provide investment recommendations specific to individual investors. As
such, the financial instruments discussed in this report may not be suitable for all investors and investors must make their own
investment decisions based upon their specific investment objectives and financial situation utilizing their own financial advisors as they
deem necessary. Investors should consider Howard Weil’s research and/or ratings as only a single factor in making their investment
decisions. Past performance of the financial instruments recommended in this report should not be taken as an indication or guarantee
of future results.
Howard Weil Incorporated is a multidisciplined financial services firm that regularly intends to seek investment banking business with
companies covered in its research reports, and thereby seeks to receive compensation from these companies for services including,
but not limited to, acting as an underwriter in an offering or financial advisor in a merger or acquisition, or serving as a placement agent
for private transactions. As a result, investors should be aware that the firm may have a conflict of interest that could affect the
objectivity of this report.
For applicable current disclosures for all covered companies, please write to the Howard Weil Research Department at the following
address:
Howard Weil Research Department
1100 Poydras Street, Suite 3500
New Orleans, Louisiana 70163
Guide to Howard Weil’s Equity Research Rating System
Howard Weil analysts use a relative rating system in which they determine a rating for stocks in Howard Weil’s Exploration and
Production, sector by a stock’s return potential relative to the S&P 500. For purposes of the disclosures required by FINRA rules,
Focus List Stock and Market Outperform equate to Buy, Market Perform equates to Hold and Market Underperform equates to Sell.
Research and current price targets are available at www.howardweil.com, or contact your Howard Weil representative.
Analysts’ Compensation
The equity research analyst(s) responsible for the preparation of this report, receive compensation based upon various factors,
including effectiveness of research recommendations, client feedback, competitive factors and overall firm revenues, which may include
revenues from, among other business units, Institutional Equities and Investment Banking.
Additional Disclaimers and Disclosures
The information contained herein has been prepared from sources believed reliable, but is not guaranteed by us and is not a complete
summary or statement of all available data, nor is it considered an offer to buy or sell any securities referred to herein. No investments
or services mentioned are available in the European Economic Area to private customers or to anyone in Canada other than a
Designated Institution.
Opinions expressed are subject to change without notice and do not take into account the particular investment objectives, financial
situation or needs of individual investors. Employees of Howard Weil Incorporated or its affiliates may, at times, release written or oral
commentary, technical analysis or trading strategies that differ from the opinions expressed within.
This email may be considered advertising under federal law. If you decide not to receive Howard Weil products and services, updates,
and information via email, please reply to howardweil@howardweil.com and ask to be removed.
Additional information is available upon request
03/2011 Howard Weil Incorporated
Member FINRA Member SIPC
1100 Poydras Street, Suite 3500, New Orleans, LA 70163
1.800.322.3005
Page 33 of 33
Howard Weil