Attached files
| file | filename |
|---|---|
| 8-K - FORM 8-K - REX ENERGY CORP | d8k.htm |
| EX-99.1 - PRESS RELEASE - REX ENERGY CORP | dex991.htm |
 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
Exhibit 99.2 |
 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 Looking Statements
Forward Looking Statements |
 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.
Hydrocarbon Value Estimates
Hydrocarbon Value Estimates
3 |
 Rex Energy
Overview Rex Energy Overview
4
Significant upside in two high growth shale plays and tertiary oil recovery
•
1.4
–
2.0
Tcfe
in
non-proven
Marcellus
Shale
resource
potential
(1)
•
17.4
–
30.5
Mmboe
in
non-proven
Niobrara
Shale
resource
potential
(1)
•
24.2
–
60.6
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
Strong Balance Sheet & Liquidity
(4)
•
$11.0
million
cash
•
$10.1
million
in
debt
•
$115.0
million
available
on
line
of
credit
•
Borrowing
base
redetermination
in
February,
2011
•
$30.0
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 14.
2. Unaudited fourth quarter 2010 results
3. Based on year-end 2010 reserves
4. Unaudited financial results as of 12/31 |
 Areas of
Operation Areas of Operation
Appalachian Region
•
57,000 net acres in Marcellus Shale fairway
o
61% of acreage in liquids rich portion of the play
o
Total
non-proven
resource
potential
of
1.4
–
2.0
Tcfe
(1)
o
$30.0 million in drilling carries
(2)
Rockies Region
•
45,000 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 17.4 –
30.5 MMBoe
(1)
Illinois Region
•
Tertiary recovery oil projects
o
Total
non-proven
resource
potential
of
24.2
–
60.6
MMBbls
from
ASP
flooding
in
the
Lawrence
Field
(1)
5
1. Assumptions based on full development program. Actual results may vary
significantly. Not proved. See “Hydrocarbon Volume Estimates” on page 3 and page 14.
2. Unaudited financial results as of 12/31/2010
3. Includes 8,300 net farm in acres |
 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 400 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%
•
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 encouraging results in the Niobrara
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)
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 |
 2010
Reserves by Asset Region PDP
PDNP
PUD
Total
(1)
Total Appalachia
27,227
9,022
116,407
152,656
Conventional
6,015
-
-
6,015
Marcellus
21,212
9,188
116,407
146,808
Illinois
48,857
-
-
48,857
Total
76,084
9,022
116,407
201,679
1. Year-end 2010 reported in Mmcfe
Total Proved Reserves
Proved Developed Producing Reserves
9 |
 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.
10
1. Including the $30M drilling carry, the 2011
budget would be $178.8M. |
 2011
Capital Budget 2011 Capital Budget
11 |
 Current
Hedging Summary Current Hedging Summary
Current Production Hedged
•
Percentage of production hedged based on December,
2010 exit rate with built in decline
12
1.
~30% of current natural gas production covered in 2011 by put spread with a $3.84 short
put price for a $1.04 put spread 2.
~21% of current natural gas production covered in 2011 by put spread with a $4.00 short
put price for a $1.75 put spread (1)
(2) |
 Marcellus
Overview Marcellus Overview
Butler County (Operated)
•
49,400 gross (34,100 net) acres
•
Joint Venture with Sumitomo in Butler County
o
70% Rex / 30% Sumitomo
o
$14.2 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)
•
49,000 gross (19,700 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
$15.8 million in Sumitomo drilling carries remaining
Other Operated Marcellus Acreage
•
17,900 gross (2,700 net) acres in areas of Clearfield,
Centre, Somerset and Fayette counties
13
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 |
 Marcellus
Operated Overview Marcellus Operated Overview
Butler County, PA
•
2010 Operational Highlights
o
Drilled 15 (10.5 net) wells in 2010, completed 8 gross
(5.6 net)
o
Placed in service 4 gross (2.8 net) wells
o
Sarsen
plant operational, currently at 30 Mmcf/d
o
49,400 gross (34,100 net) acres
•
2011 Operational Assumptions
o
Drilling the full year with one rig, and second rig by
mid year
o
Drill 24 gross (15 net) wells
o
Fracture and complete at least 24 gross (15 net) wells
o
Construction of the second 40.0 Mmcf/d
cryogenic
plant, 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
Marcellus Operated Area in PA
14 |
 •
Core acreage position of 30,500 gross (21,400net) acres
o
Allows for minimal rig movement
o
Decreases in drilling time
o
Maximizes unitized acreage
•
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 two
rig drilling program allows for
minimal
lease expirations
Why Rex Values its Presence in Butler County
Why Rex Values its Presence in Butler County
Prospective Butler Units
15
•
Inventory of 400 potential drilling locations
•
Favorable commodity price differentials |
 Marcellus
Non-Operated Overview Marcellus Non-Operated Overview
16 |
 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
1. Based on the 2010 reserve report
17 |
 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
18 |
 Niobrara
Overview Niobrara Overview
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 areal extent
•
Expected well costs of $3.5 -
$4.2 MM
DJ Basin
Rex Energy
Silo State 41-22H
201 BOE/d Test Rate
Rex Energy
BJB #1H
Drilled and Completed,
Recovering Load
Rex Energy
Herrington Farms 1H
450 BOE/d Test Rate
19
1. Assumptions based on full development program. Individual well results may vary
significantly. Not proved. See “Hydrocarbon Volume Estimates” on page 3.
~65,400 gross (45,000 net) acres
•
3 horizontal wells drilled, fractured and recovering load |
 Conceptual Niobrara Economics
Conceptual Niobrara Economics
Niobrara Horizontal Well Assumptions
•
400 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:
$13.00/Bbls
•
Severance & ad valorem taxes: 13%
Silo Field Type Curve
Before Tax IRR
20 |
 Lawrence
Field ASP Overview Lawrence Field ASP Overview
~ASP Project Summary
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
•
Wateflooded
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
Middaugh
Unit, ASP
Project
21
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.
•
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
|
 ASP
Conceptual Economics ASP Conceptual Economics
Typical ASP Flood IRR vs
Oil Price at Various PV Recoveries
22
Total ASP Potential Reserves at Various PV Recoveries
1. Estimated by Netherland, Sewell & Associates, Inc. Does not represent proved reserves. See
“Hydrocarbon Volume Estimates” on page 3. •
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
|
 •
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
Encouraging Niobrara results
o
Additional potential in the Utica and Upper Devonian shale
o
4 rig program in 2011
o
Large inventory of drilling locations
•
Financially
o
Conservative balance sheet
o
Total line of credit availability of $115 million
o
Diversified portfolio with both oil and gas
o
Strong hedging position
Why Invest in Rex Energy?
Why Invest in Rex Energy?
23 |