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| 8-K - FORM 8-K - REX ENERGY CORP | d8k.htm |
 Rex
Energy Rex Energy
Corporate Presentation
Corporate Presentation
Rex Energy Corporation | 476 Rolling Ridge Drive | State College, PA 16801
P: (814) 278-7267 | F: (814) 278-7286
E: InvestorRelations@RexEnergyCorp.com
www.rexenergy.com
Together We Can Make A Difference
April, 2011 IPAA OGIS New York
April, 2011 IPAA OGIS New York
Exhibit 99.1 |
 Forward
Looking Statements Except
for
historical
information,
statements
made
in
this
release,
including
those
relating
to
significant
potential,
future
earnings,
cash
flow,
capital
expenditures,
production
growth
and
planned
number
of
wells
(as
well
as
the
timing
of
rig
operations,
natural
gas
processing
plant
commissioning
and
operations,
fracture
stimulation
activities
and
the
completion
of
wells
and
the
expected
dates
that
wells
are
producing
hydrocarbons
that
are
sold),
are
forward-looking
statements
within
the
meaning
of
Section
27A
of
the
Securities
Act
of
1933,
as
amended,
and
Section
21E
of
the
Securities
Exchange
Act
of
1934,
as
amended.
These
forward-
looking
statements
are
indicated
by
words
such
as
“expected”,
“expects”,
“anticipates”
and
similar
words.
These
statements
are
based
on
assumptions
and
estimates
that
management
believes
are
reasonable
based
on
currently
available
information;
however,
management's
assumptions
and
the
company's
future
performance
are
subject
to
a
wide
range
of
business
risks
and
uncertainties,
and
there
is
no
assurance
that
these
goals
and
projections
can
or
will
be
met.
Any
number
of
factors
could
cause
actual
results
to
differ
materially
from
those
in
the
forward-looking
statements,
including
(without
limitation)
the
following:
•
adverse economic conditions in the United States and globally;
•
the difficult and adverse conditions in the domestic and global capital and credit
markets; •
domestic and global demand for oil and natural gas;
•
sustained or further declines in the prices the company receives for oil and natural gas;
•
the effects of government regulation, permitting and other legal requirements;
•
the geologic quality of the company’s properties with regard to, among other things,
the existence of hydrocarbons in economic quantities; •
uncertainties about the estimates of the company’s oil and natural gas reserves;
•
the company’s ability to increase production and oil and natural gas income through
exploration and development; •
the company’s ability to successfully apply horizontal drilling techniques and
tertiary recovery methods; •
the number of well locations to be drilled, the cost to drill and the time frame within
which they will be drilled; •
the effects of adverse weather on operations;
•
drilling and operating risks;
•
the ability of contractors to timely and adequately perform their drilling, construction,
well stimulation, completion and production services; •
the availability of equipment, such as drilling rigs and transportation pipelines;
•
changes in the company’s drilling plans and related budgets;
•
the adequacy of capital resources and liquidity including (without limitation) access to
additional borrowing capacity; and •
uncertainties associated with our legal proceedings and the outcome.
The company undertakes no obligation to publicly update or revise any forward-looking
statements. Further information on the company’s risks and uncertainties is
available in the company's filings with the Securities and Exchange Commission.
The company's internal estimates of reserves may be subject to revision and may be
different from estimates by the company's external reservoir engineers at year
end. Although the company believes the expectations and forecasts reflected in these and other forward-looking statements are reasonable, it can give no
assurance they will prove to have been correct. They can be affected by inaccurate
assumptions or by known or unknown risks and uncertainties. 2
Forward
Forward
Looking
Looking
Statements
Statements |
 Hydrocarbon Value Estimates
Hydrocarbon Value Estimates
3
Hydrocarbon Volume Estimates
This presentation includes management’s estimates of Marcellus Shale potential
recoverable resources, per well EUR (estimated ultimate recovery of resources) and
upside potential of recoverable resources. Except as noted, these have been estimated internally by the Company without review by independent engineers
and do not necessarily constitute reserves. These estimates are included to
demonstrate the potential for future drilling by the Company. Actual recovery of
these potential volumes is inherently more speculative than recovery of estimated proved
reserves. Estimates of potential recoverable resources, per well EURs and
upside potential for Company oil and gas shale acreage are particularly speculative due to the limited experience in Marcellus Shale horizontal development,
with its limited production history. Ultimate recoveries will be dependent upon
numerous factors including actual encountered geological conditions, the impact of
future oil and gas pricing and exploration costs, and our future drilling decisions and budgets based upon our future evaluation of risk, returns and the
availability of capital and, in many areas, the outcome of negotiation of drilling
arrangements with holders of adjacent or fractional interest leases. In addition,
potential recoverable resources are based on undesignated future well locations under
assumed acreage spacing which may not have been specifically included in any
definitive development plan and ultimately may not be drilled. Accordingly, such estimates may differ significantly from the hydrocarbon quantities that
are ultimately recovered.
SEC rules prohibit a publicly-reporting oil and gas company from including oil and
gas resource estimates in their filings with the SEC, except proved, probable and
possible reserves that meet the SEC’s definitions of such terms. Illinois Basin estimates (including Lawrence Field) of oil in place and other resource
volumes, oil in place and other reserve volumes indicated herein are not based on SEC
definitions and guidelines. Unless otherwise indicated, estimates of non-
proved reserves and other hydrocarbons included herein may not meet specific definitions
of reserves or resource categories within the meaning of the SPE/SPEE/WPC
Petroleum Resource Management System. |
 Rex
Rex
Energy
Energy
Overview
Overview
Significant upside in two high growth shale plays and tertiary oil recovery
•
1.2
–
1.9
Tcfe
in
non-proven
Marcellus
Shale
resource
potential
(1)
•
9.5
–
22.8
Mmboe
in
non-proven
Niobrara
Shale
resource
potential
(1)
•
24.9
–
62.2
Mmbls
in
non-proven
Tertiary
Recovery
oil
resource
potential
(1)
Liquids Rich Production & Proven Reserves
•
Total
production
of
22.8
Mmcfe/d
(3,793
BOE/d)
(2)
o
53% oil and NGLs
•
202
Bcfe
(33.6
Mmbls)
proven
reserves
(3)
o
62% of proved developed is attributable oil and NGLs
o
85% liquids rich capture
•
PV-10
value
of
$269.4
million
(3)
Strong
Balance
Sheet
&
Liquidity
(4)
•
$6.1 million cash
•
$30.0 million in debt
•
Borrowing base increased to $160.0 million in March, 2011
•
$130.0 million available on line of credit
•
$11.6 million in Marcellus drilling carries
1. Assumptions
based
on
full
development
program.
Actual
results
may
vary
significantly.
Not
proved.
See
“Hydrocarbon
Volume
Estimates”
on
page
3
and
page
12.
2. Fourth quarter 2010 results
3. Based on year-end 2010 reserves
4. Unaudited financial results as of 2/28/2011
4 |
 Areas of
Operation Areas of Operation
Appalachian Region
•
56,000 net acres in Marcellus Shale fairway
o
61% of acreage in liquids rich portion of the play
o
Total
non-proven
resource
potential
of
1.2 –
1.9
Tcfe
(1)
o
$11.6 million in drilling carries
(2)
Rockies Region
•
39,000
net
acres
in
Niobrara
Shale
fairway
(3)
o
100% of acres in oil window of the
Niobrara in the DJ Basin
o
Total non-proven resource potential
of 9.5 –
22.8 MMBoe
(1)
Illinois Region
•
Tertiary recovery oil projects
o
Total
non-proven
resource
potential
of
24.9
–
62.2
MMBbls
from
ASP
flooding
in
the
Lawrence
Field
(1)
1. Assumptions
based
on
full
development
program.
Actual
results
may
vary
significantly.
Not
proved.
See
“Hydrocarbon
Volume
Estimates”
on
page
3
and
page
12.
2. Unaudited financial results as of 2/28/2011
3. Includes 8,300 net farm in acres
5 |
 Key
Investment Highlights for 2011 Key Investment Highlights for 2011
•
Rex Energy is positioned for growth
o
Strong position in oil and liquids-rich areas
o
Company expects 2011 production growth of 71%-95% over 2010
•
Strong core position in the Appalachian Basin
o
Solid core position in Butler County with 385 potential drill sites
in the Marcellus Shale, with additional potential in the Utica and
Upper Devonian Shale
•
Strong track record of growth with a historical reserve
CAGR of 75% and low F&D cost
•
Rex Energy is equipped to thrive in a low gas price
environment
o
74% of the 2011 capital budget is dedicated to oil and
liquids rich project areas.
o
65% of the Appalachian capital budget is allocated to
liquids rich Butler County
•
Secured key drilling, fracture stimulation, and tubular
services for the next two years
•
Opportunities for growth within tertiary recovery projects in
the Illinois Basin and preliminary results in the Niobrara
•
Investment in human capital
6 |
 Positioned
For Growth Positioned For Growth
•
Poised to achieve 71% -
95% production growth in 2011
•
Expect to see 22% -
40% growth in oil and NGL production in 2011
•
A mid case December exit rate of 45.6 Mmcfe/day in 2011 represents an 83% increase
compared to the 2010 exit rate 7 |
 Reserve
Growth Reserve Growth
Proved Reserve & Compound Annual Growth Rate
Year-End 2010
(1)
•
33.6 Mmboe (201.7Bcfe)
•
Drill Bit F&D cost of $0.68/ Mcfe
•
$269.4 million PV-10
o
42% proved developed
o
37% oil & NGLs
o
85% liquids rich capture
Year-End 2009
(2)
•
20.9 Mmboe (125.2 Bcfe)
•
$190.5 million PV-10
o
54% proved developed
o
55% oil & NGLs
Year-End 2008
(3)
•
10.9 Mmboe (65.4 Bcfe)
•
$84.0 million PV-10
o
62% proved developed
o
52% oil
1. Year-end 2010 reserves calculated using $75.96 per Bbl and $4.38 per Mcf.
2. Year-end 2009 reserves calculated using $57.65 per Bbl and $3.87 per Mcf.
3. Year-end 2008 reserves calculated using $41.00 per Bbl and $5.71 per Mcf.
8 |
 2011
Capital Budget 2011 Capital Budget
•74%
of
the
total
budget
is
allocated
to
oil
and
liquids
rich
gas
operations.
•65% of the Appalachian
budget is dedicated to liquids rich Butler County operations.
9
Capital Budget
(Net of Drilling Carries)
($ in millions)
Appalachia
Illinois
Rockies
Total
Drilling & Exploitation
$81.4
$3.0
$21.0
$105.4
Tertiary Recovery Projects
-
$0.7
-
$0.7
Facilities,
Equipment & HSE
$0.9
$7.5
$1.0
$9.4
Leasing
& Land
$10.0
-
$5.0
$15.0
Midstream
$18.0
-
-
$18.0
Corporate
-
-
-
$0.3
Total Uses
$
110.3
$11.2
$27.0
$148.8
Gross (Net) Operated Wells Budgeted
25 Gross
(16 Net)
-
5 Gross
(5 Net)
30 Gross
(21 Net)
Gross (Net) Non Operated Wells Budgeted
20 Gross
(8 Net)
9 Gross
(4 Net)
-
29 Gross
(12 Net) |
 Capital
Allocation by Commodity Capital Allocation by Region
Capital Allocation by Activity Type
Capital Allocation by Operatorship
2011 Capital Budget
2011 Capital Budget
10 |
 Current
Hedging Summary Current Hedging Summary
11
1.
~10%
of
2011
mid
point
guidance
natural
gas
production
covered
in
2011
by
put
spread
with
a
$3.68
short
put
price
for
a
$1.04
put
spread
2. ~11% of 2011 mid point natural gas production covered in 2011 and 2012 by
put spread with a $4.00 short put price for a $1.75 put spread Natural
Gas
% of Current
with Floor
% of Current
with Ceiling
Avg. Floor
Price
Avg. Ceiling
Price
2011
(1)(2)
75%
56%
$ 5.26
$5.67
2012
(2)
57%
57%
$
4.94
$
5.97
2013
58%
58%
$
5.00
$
6.25
Crude Oil
% of Current
with Floor
% of Current
with Ceiling
Avg. Floor
Price
Avg. Ceiling
Price
2011
87%
87%
$68.54
$104.69
2012
87%
87%
$67.10
$112.03
2013
41%
41%
$70.50
$120.00
Current Production Hedged
•
Percentage of production hedged based on 2011 mid point
of guidance with decline built in |
 Marcellus
Overview Marcellus Overview
Butler County (Operated)
•
47,500 gross (34,000 net) acres
•
Joint Venture with Sumitomo in Butler County
o
70% Rex / 30% Sumitomo
o
$2.4 million in Sumitomo drilling carries remaining
•
Butler Midstream Joint Venture
o
60% Stonehenge / 28% Rex / 10% Sumitomo
o
Operation
of
40
Mmcf/d
cryogenic
plant
o
Pipeline infrastructure
Westmoreland, Centre, and Clearfield Counties
(Non Operated)
•
47,000 gross (19,000 net) acres
•
Joint Venture among Williams, Rex, and Sumitomo
o
50% Williams / 40% Rex / 10% Sumitomo
o
JV includes interest in gathering and transportation
o
$9.2 million in Sumitomo drilling carries remaining
Other Operated Marcellus Acreage
•
17,500 gross (3,000 net) acres in areas of Clearfield, Centre, Somerset and Fayette
counties 1. Assumptions
based
on
full
development
program.
Individual
well
results
may
vary
significantly.
Not
proved.
See
“Hydrocarbon
Volume
Estimates”
on
page
3.
2. Includes approximately 129 Bcfe of Marcellus Shale proved reserves as of December
31, 2010 12 |
 Marcellus
Operated Overview Marcellus Operated Overview
Butler County, PA
•
2011 Operational Assumptions
o
Drilling the full year with one rig, and second rig by
mid year
o
Plan to drill 25 gross (16 net) wells
o
Fracture and complete at least 24 gross (15 net) wells
o
Construction of the second cryogenic plant (Bluestone),
proposed commissioning in first quarter 2012
o
Primary leasing strategy will fill in future drilling units, and
other
contiguous
acreage
blocks
within
the
core
operational area
•
2011 Operational Update
o
Drilled 6 gross (4 net) wells
o
Fractured and completed 6 gross (4 net) wells
o
Placed in service 10 gross (7 net) wells
o
Picked up a second rig in April
o
5 day average rate on four of the five Drushel wells at 3.7
Mmcfe/day
Average lateral length of 3,200 feet
Fifth well not yet fractured
o
Bluestone cryogenic plant capacity permit request increased
from 40.0 Mmcf/d to 50.0 Mmcf/d
o
Third cryogenic plant permit expected to be filed within 5 days
Marcellus Operated Area in PA
13
Columbia
Dominion
Natural Fuel
REX Leasehold |
 •
Core acreage position of 30,500 gross (21,400 net) acres
o
Allows for minimal rig movement
o
Decreases in drilling time
o
Maximizes unitized acreage
•
Approximately 385 drilling locations
•
Favorable commodity price differentials
•
Close access to infrastructure and pipelines
•
Terrain composition very accessible
•
Low risk geological area
•
Additional production possibilities in the Utica and
Upper Devonian Shale
•
Maintaining a two rig drilling program allows for
minimal lease expirations
Why
Why
Rex
Rex
Values
Values
its
its
Presence
Presence
in
in
Butler
Butler
County
County
Prospective Butler Units
14 |
 Butler
Operated Butler Operated
Drilling & Completion Schedule
Drilling & Completion Schedule
Rig
Pad
Pad
Gross Well
Gross Well
Count
Count
Net Well
Net Well
Count
Count
Status
Status
UDI 54
Drushel
(1)
5.0
3.5
Fractured and placed in service four of the five wells
UDI 54
Talarico
3.0
2.1
All wells drilled, awaiting fracture and completion in 2Q11
UDI 54
Grosick
7.0
3.0
Pilot holes drilled, horizontal rig drilling third well
UDI 54
Carson
3.0
2.1
Pad construction phase
UDI 54
Bricker
4.0
2.8
Permitting
Total UDI 54
22.0
13.5
UDI 52
McElhinney
2.0
1.4
Pilot holes drilled, horizontal rig drilling second well
UDI 52
Behm
3.0
2.1
Pad construction phase
UDI 52
Grahm
3.0
2.1
Pad construction phase
UDI 52
Meyer
3.0
2.1
Pad construction phase
Total UDI 52
11.0
7.7
Bronco 10
Gilliland
(2)
6.0
4.2
Pilot holes drilled, awaiting horizontal rig start up in mid April
Bronco 10
Cheeseman
(3)
1.0
0.7
Awaiting vertical and horizontal rig
Total Bronco 10
7.0
4.9
15
1. Four of the five Drushel wells were drilled in 2010
2. Includes one Burkett test well
3. Utica well test |
 Marcellus
Non-Operated Overview Marcellus Non-Operated Overview
16
Sizeable acreage position with 47,000 gross (19,000 net) acres
2011 Operational Assumptions
Two rig program for the full year
Plan to drill 20 gross (8 net) wells
Fracture and complete at least 19 gross (8 net) wells
Transportation & Gathering
Westmoreland
14.0 Mmcf/d flowing through Dominion at the Ecker tap
Additional
24
Mmcf/d
pipeline
construction
to
the
Equitrans
expected
May
1
st
Clearfield
Firm 10.0 Mmcf/d transportation with Columbia Gas in Clearfield with the current option
to add an additional 30.0 Mmcf/d
2011 Operational Update
Drilled 8 gross (3 net) wells
Beginning fracture and completion on two of the five Uschak wells with four additional
wells to be fracture and completed in May
Six additional wells should be available for fracture and completion by
mid-year Placed in service 1 gross (.4 net) well
Additional
24
Mmcf/d
pipeline
construction
to
the
Equitrans
expected
May
1
st
Westmoreland, Clearfield and Centre Counties, PA |
 County
Rig
Pad
Pad
Gross Well
Gross Well
Count
Count
Net Well
Net Well
Count
Count
Status
Status
Westmoreland
H&P 287
Uschak #2
5.0
2.0
Awaiting fracture and
stimulation
Westmoreland
H&P 287
Androstic
3.0
1.2
Drilled, awaiting fracture and
stimulation
Westmoreland
H&P 287
National
Metals
2.0
0.8
Rig drilling first of two wells
Westmoreland
H&P 287
Frye
2.0
0.8
Awaiting drilling rig
Westmoreland
H&P 287
McBroom
3.0
1.2
Awaiting drilling rig
Total H&P 287
15.0
6.0
Westmoreland
Patterson 480
Uschak #1
4.0
1.6
Drilled, awaiting fracture and
completion
Westmoreland
Patterson 480
Marco
3.0
1.2
Rig drilling first of three wells
Total Patterson 480
7.0
2.8
Clearfield
Patterson 332
Resource
Recovery #1
4.0
1.6
Rig Drilling second of four
wells
Total Patterson 332
4.0
1.6
Westmoreland & Clearfield Non Operated
Westmoreland & Clearfield Non Operated
Drilling & Completion Schedule
Drilling & Completion Schedule
17 |
 Conceptual Marcellus Economics
Conceptual Marcellus Economics
Butler County (Wet Gas) Assumptions
(1)
•
2.5 MMcf/d IP Rate
•
4.4 Bcfe gross EUR
•
$4.7 million drilling and completion costs
•
15% royalties
•
Gas Price Basis Adjustment: $0.26/Mcf
•
NGL
&
condensate
volumes:
1.64
gallons
per
Mcf
(~39
Bbls
per MMcf)
•
NGL price assumptions: $0.76/gal (~40% of NYMEX oil price)
•
Gathering transportation & operating expenses: $1.50/Mcf
Westmoreland & Central PA (Dry Gas)
Assumptions
(1)
•
3.5 MMcf/d IP Rate
•
3.0 Bcf gross EUR
•
$4.7 million drilling and completion costs
•
15% royalties
•
Gas price basis adjustment: ($.09)/Mcf
•
Gathering transportation & operating expenses: $0.67/Mcf
Type Curves
Before Tax IRR
1. Based on the 2010 reserve report
18 |
 Marcellus
Well Cost Comparison Marcellus Well Cost Comparison
Reserve Well Economics
•Average Well Cost of $4.7
million
•Average
Drilling
and
Completion
cost
-
$1.9
million
•Average Frac Cost -
$2.2 million
•Average Equipment cost
- $0.6
million 1. Results from the 2010 Drilling Program
19 |
 Niobrara
Overview Niobrara Overview
~56,000 gross (39,000 net) acres
•
3 horizontal wells drilled (infill and Matrix Porosity
results)
DJ Basin Niobrara Summary
•
Thick “Source Rock”
–
300+ ft.
•
High total organic content (TOC’s) of 2-10%
•
Strong
matrix
contribution
from
high
porosity
chalks
•
Production likely influenced by faults and fractures
•
Mature over large aerial extent
•
Expected well costs of $3.5 -
$4.2 MM
DJ Basin
Rex Energy
Silo State 41-22H
IP: 67 BOE/d
Rex Energy
BJB #1H
Appears Non-
Commercial
Rex Energy
Herrington Farms 1H
IP: 202 BOE/d
1. Assumptions
based
on
full
development
program.
Individual
well
results
may
vary
significantly.
Not
proved.
See
“Hydrocarbon
Volume
Estimates”
on
page
3.
20
Silo
Field
Rex Energy
Shapley 14-45H
Drilling |
 Conceptual Niobrara Economics
Conceptual Niobrara Economics
Niobrara Horizontal Well Assumptions
•
300 Bbls/d IP
•
Gas sales start 18 months after oil sales
•
$4.2 million drilling and completion costs
•
18% royalties
•
Oil price basis adjustment: -$9.00/Bbls
•
Gathering transportation & operating expenses:
$13.05/Bbls
•
Severance & ad valorem taxes: 13%
21
Before Tax IRR
Silo Field Type Curve |
 Lawrence
Field ASP Overview Lawrence Field ASP Overview
~ASP Project Summary
•
ASP stands for Alkali-Surfactant-Polymer flood
•
Alkali-Surfactant mix reduces interfacial tension allowing remaining oil to flow
easier through the formation •
Polymer
improves
sweep
efficiency
by
forcing
fluid
into
parts
of
the
field
not
effectively
swept
by
the
waterflood
•
Based on NSAI geological analysis and high grading of the acreage, 27 separate ASP units
have been designed to date. •
Laboratory
analysis
on
the
effect
of
ASP
flooding
of
cores
from
the
field
recovered
23%
of
OOIP
(16%
PV
(1)
Recovery)
•
Single
well
pilot
test
of
ASP
flooding
in
the
field
recovered
27%
of
OOIP
(20%
PV
(1)
Recovery)
•
Injecting chemicals on 15-acre unit with initial response expected in late first
quarter 2011 to early second quarter 2011 •
Currently at 25% of pore volume (PV) injected ASP slug, currently injecting polymer
push Illinois Basin
~13,100 gross (13,000 net) acres in Lawrence Field
•
1 billion barrels of original-oil-in-place (OOIP)
•
Field has produced 400 MMBbls since 1906
•
Water flooded in the 1950’s
•
Two successful surfactant-polymer flood pilots completed by Marathon
with 15-20% of OOIP recovered
•
Field currently produces ~1,600 gross (1,250 net) barrels per day under
waterflood
1. Pore
volume
recovery
assumptions
based
on
full
development
program.
Individual
ASP
unit
results
may
vary
significantly.
Not
proved.
See
“Hydrocarbon
Volume
Estimates”
on
page
3.
Middaugh Unit, ASP
Project
22
REX Acreage |
 ASP
Conceptual Economics ASP Conceptual Economics
•
Capital for the ASP plant has already been spent
•
90% of future capital will be chemical costs
•
North & Central areas of the field have been analyzed to date (~75% of the
field) o
Identified
18
target
continuous
sand
bodies
and
broke
these
down
into
27
separate
flood
units
(15
Bridgeport/
12 Cypress)
o
Base
case
probable
reserves
in
identified
floodable
sands:
39.4
MMBbls
(1)
in
the
Northern
&
Central
areas
of
the field at a 13% PV Recovery
Typical ASP Flood IRR vs Oil Price at Various PV Recoveries
1. Estimated
by
Netherland,
Sewell
&
Associates,
Inc.
Does
not
represent
proved
reserves.
See
“Hydrocarbon
Volume
Estimates”
on
page
3.
23
Total ASP Potential Reserves at Various PV Recoveries |
 •
Operationally
o
Estimated annual production growth of 71% -
95% in 2011
o
74% of 2011 capital budget allocated to oil and liquids rich operating areas
o
Strong growth with a historical reserve CAGR of 75%
o
Preliminary Niobrara results
o
Additional potential in the Utica and Upper Devonian shale
o
4 full time rig program in 2011
o
Large inventory of drilling locations
•
Financially
o
Conservative balance sheet
o
Total line of credit availability of $130 million
o
Diversified portfolio with both oil and gas
o
Strong hedging position
Why Invest in Rex Energy?
Why Invest in Rex Energy?
24 |