EX-99.2 3 d159038dex992.htm EX-99.2 EX-99.2
Second Quarter 2015 Results
AUGUST 5, 2015
Exhibit 99.2

Forward-looking statements
2
This
presentation
contains
forward-looking
statements
within
the
meaning
of
Section
27A
of
the
Securities
Act
of
1933
and
Section
21E
of
the
Securities
Exchange
Act
of
1934.
All
statements,
other
than
statements
of
historical
facts,
included
in
this
presentation
that
address
activities,
events
or
developments
that
the
Company
expects,
believes
or
anticipates
will
or
may
occur
in
the
future
are
forward-looking
statements.
Without
limiting
the
generality
of
the
foregoing,
forward-looking
statements
contained
in
this
presentation
specifically
include
the
expectations
of
management
regarding
plans,
strategies,
objectives,
anticipated
financial
and
operating
results
of
the
Company,
including
as
to
the
Company’s
Wolfcamp
shale
resource
play,
estimated
resource
potential
and
recoverability
of
the
oil
and
gas,
estimated
reserves
and
drilling
locations,
capital
expenditures,
typical
well
results
and
well
profiles,
type
curve,
and
production
and
operating
expenses
guidance
included
in
the
presentation.
These
statements
are
based
on
certain
assumptions
made
by
the
Company
based
on
management's
experience
and
technical
analyses,
current
conditions,
anticipated
future
developments
and
other
factors
believed
to
be
appropriate
and
believed
to
be
reasonable
by
management.
When
used
in
this
presentation,
the
words
“will,”
“potential,”
“believe,”
“intend,”
“expect,”
“may,”
“should,”
“anticipate,”
“could,”
“estimate,”
“plan,”
“predict,”
“project,”
“target,”
“profile,”
“model”
or
their
negatives,
other
similar
expressions
or
the
statements
that
include
those
words,
are
intended
to
identify
forward-looking
statements,
although
not
all
forward-looking
statements
contain
such
identifying
words.
Such
statements
are
subject
to
a
number
of
assumptions,
risks
and
uncertainties,
many
of
which
are
beyond
the
control
of
the
Company,
which
may
cause
actual
results
to
differ
materially
from
those
implied
or
expressed
by
the
forward-looking
statements.
In
particular,
careful
consideration
should
be
given
to
the
cautionary
statements
and
risk
factors
described
in
the
Company's
most
recent
Annual
Report
on
Form
10-K
and
Quarterly
Reports
on
Form
10-Q.
Any
forward-looking
statement
speaks
only
as
of
the
date
on
which
such
statement
is
made
and
the
Company
undertakes
no
obligation
to
correct
or
update
any
forward-looking
statement,
whether
as
a
result
of
new
information,
future
events
or
otherwise,
except
as
required
by
applicable
law.
The
Securities
and
Exchange
Commission
(“SEC”)
permits
oil
and
gas
companies,
in
their
filings
with
the
SEC,
to
disclose
only
proved,
probable
and
possible
reserves
that
meet
the
SEC’s
definitions
for
such
terms,
and
price
and
cost
sensitivities
for
such
reserves,
and
prohibits
disclosure
of
resources
that
do
not
constitute
such
reserves.
The
Company
uses
the
terms
“estimated
ultimate
recovery”
or
“EUR,”
reserve
or
resource
“potential,”
and
other
descriptions
of
volumes
of
reserves
potentially
recoverable
through
additional
drilling
or
recovery
techniques
that
the
SEC’s
rules
may
prohibit
the
Company
from
including
in
filings
with
the
SEC.
These
estimates
are
by
their
nature
more
speculative
than
estimates
of
proved,
probable
and
possible
reserves
and
accordingly
are
subject
to
substantially
greater
risk
of
being
actually
realized
by
the
Company.
EUR
estimates,
identified
drilling
locations
and
resource
potential
estimates
have
not
been
risked
by
the
Company.
Actual
locations
drilled
and
quantities
that
may
be
ultimately
recovered
from
the
Company’s
interest
may
differ
substantially
from
the
Company’s
estimates.
There
is
no
commitment
by
the
Company
to
drill
all
of
the
drilling
locations
that
have
been
attributed
these
quantities.
Factors
affecting
ultimate
recovery
include
the
scope
of
the
Company’s
drilling
project,
which
will
be
directly
affected
by
the
availability
of
capital,
drilling
and
production
costs,
availability
of
drilling
and
completion
services
and
equipment,
drilling
results,
lease
expirations,
regulatory
approval
and
actual
drilling
results,
as
well
as
geological
and
mechanical
factors.
Estimates
of
unproved
reserves,
type/decline
curves,
per
well
EUR
and
resource
potential
may
change
significantly
as
development
of
the
Company’s
oil
and
gas
assets
provides
additional
data.
Type/decline
curves,
estimated
EURs,
resource
potential,
recovery
factors
and
well
costs
represent
Company
estimates
based
on
evaluation
of
petrophysical
analysis,
core
data
and
well
logs,
well
performance
from
limited
drilling
and
recompletion
results
and
seismic
data,
and
have
not
been
reviewed
by
independent
engineers.
These
are
presented
as
hypothetical
recoveries
if
assumptions
and
estimates
regarding
recoverable
hydrocarbons,
recovery
factors
and
costs
prove
correct.
The
Company
has
limited
production
experience
with
this
project,
and
accordingly,
such
estimates
may
change
significantly
as
results
from
more
wells
are
evaluated.
Estimates
of
resource
potential
and
EURs
do
not
constitute
reserves,
but
constitute
estimates
of
contingent
resources
which
the
SEC
has
determined
are
too
speculative
to
include
in
SEC
filings.
Unless
otherwise
noted,
IRR
estimates
are
before
taxes
and
assume
NYMEX
forward-curve
oil
and
gas
pricing
and
Company-generated
EUR
and
decline
curve
estimates
based
on
Company
drilling
and
completion
cost
estimates
that
do
not
include
land,
seismic
or
G&A
costs.
Cautionary statements regarding oil & gas quantities
Second Quarter 2015 Results –
August 2015

Company overview
AREX OVERVIEW
ASSET OVERVIEW
Enterprise value $671MM
High-quality reserve base
146 MMBoe proved reserves
66% Liquids, 38% oil
$1.4 BN proved PV-10
Permian core operating area
143,000 gross (130,000 net) acres
~1+ BnBoe gross, unrisked resource potential
~2,000 Identified HZ drilling locations targeting
Wolfcamp A/B/C
2015 Capital program focused on flexibility
and returns
-
Running an average of 1 HZ rig in the Wolfcamp
shale play with a reduced capital budget of
approximately $150 MM
-
Completed drilling activities and commitments
ahead of schedule
-
Deferred three completions to post-2015
Note:
Proved
reserves
as
of
12/31/2014
and
acreage
as
of
6/30/2015.
All
Boe
and
Mcfe
calculations
are
based
on
a
6
to
1
conversion
ratio.
Enterprise
value
is
equal
to
market
capitalization
using
the
closing
share
price
of
$4.25
per
share
on
7/29/2015,
plus
net
debt
as
of
6/30/2015.
See
“PV-10
(unaudited)”
slide.
3
Second Quarter 2015 Results –
August 2015

2Q15 Key highlights
4
2Q15 HIGHLIGHTS
•
Drilled 9 and completed 10 HZ wells
•
Continued improvement on already best-
in-class HZ well costs
•
Increased 2Q15 production 8% YoY to 15.3
MBoe/d
•
Reduced cash operating cost 26% YoY to
$11.02/Boe
•
Reduced LOE 20% YoY to $4.97/Boe
2Q15  SUMMARY RESULTS
Production (MBoe/d)
15.3
% Oil
36%
% Total liquids
65%
Average
realized price ($/Boe)
Average realized price,
excluding commodity derivatives
impact
$
27.76
Average realized price,
including commodity derivatives
impact
34.44
Costs
and expenses ($/Boe)
LOE
$
4.97
Production and ad valorem taxes
2.14
Exploration
0.84
General and administrative
5.40
G&A –
cash
component
3.91
G&A –
noncash component
1.49
DD&A
20.43
Note: See “Cash operating expenses” slide.
Second Quarter 2015 Results –
August 2015

2Q15 Operating highlights
OPERATING HIGHLIGHTS
Maximizing
Returns
•
Successfully implemented cost reduction initiatives, current HZ well costs now averaging
$4.5 MM per well, down 15+% from 2014 average of $5.5 MM
•
D&C cost savings includes $450,000 per well of permanent savings from water recycling
•
LOE of $4.97/Boe, improved 20% YoY
Tracking
Development
Plan
•
Drilled 9 HZ wells and completed 10 HZ
wells, with 2 additional wells in final stages of
completion
•
Wolfcamp B –
5 wells and Wolfcamp C –
5 wells
•
2Q15 HZ Wolfcamp average IP 869 Boe/d (58% oil, 81% liquids)
Delivering
Production
Growth
•
Total record quarterly production 15.3 MBoe/d (up 8% QoQ)
•
Oil production 499 MBbl
(up 1% QoQ)
5
Second Quarter 2015 Results –
August 2015

2Q15 Financial highlights
FINANCIAL HIGHLIGHTS
Preserving Cash
Flow
•
Quarterly EBITDAX (non-GAAP) of $32.6 MM, or $0.80 per diluted share
•
Capital expenditures of $56.9 MM ($53.5 MM for D&C)
•
Remain well-hedged for the balance of 2015, added 2016 oil hedges
•
Reduced 2015 capex from $160 MM to $150 MM
Stable Financial
Position
•
Liquidity of $193MM at June 30
th
•
Lenders reaffirmed $450 MM commitment amount following Spring 2015 redetermination
Heightened
Focus on Cutting
Costs
•
Revenues (pre-hedge) of $38.6 MM, $47.9 MM with hedges
•
Adjusted net loss (non-GAAP) of $2.8 MM, or $0.07 per diluted share
•
Every per-unit cash cost metric has improved since 2Q14
•
2Q15 Cash operating costs totaled $11.02/Boe, a 26% decrease compared to 2Q14 and an
11% improvement over 1Q15 
Note: See “Adjusted Net Income,” “EBITDAX,” “Strong, Simple Balance Sheet, and “Cash operating expenses” slides.
6
Second Quarter 2015 Results –
August 2015

Lowest cost structure in the Permian Basin
7
$7.36
$6.18
$5.87
$6.65
$5.55
$4.97
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$7.00
$8.00
1Q14
2Q14
3Q14
4Q14
1Q15
2Q15
AREX LOE Historical Track Record ($/Boe)
Permian Peer LOE ($/Boe)
AREX D&C Historical Track Record ($ MM)
Permian Peer D&C Cost ($ MM)
$13.26
$11.23
$9.63
$9.03
$8.78
$8.14
$7.83
$7.58
$4.97
$0.0
$2.0
$4.0
$6.0
$8.0
$10.0
$12.0
$14.0
Peer 1
Peer 2
Peer 3
Peer 4
Peer 5
Peer 6
Peer 7
Peer 8
AREX
$8.6
$7.0
$5.8
$5.5
$4.5
$4.3
$0.0
$1.0
$2.0
$3.0
$4.0
$5.0
$6.0
$7.0
$8.0
$9.0
2011
2012
2013
2014
Current
2Q15 Best
Well
$8.5
$7.0
$6.6
$6.5
$6.3
$6.3
$6.1
$6.0
$4.5
$0.0
$1.0
$2.0
$3.0
$4.0
$5.0
$6.0
$7.0
$8.0
$9.0
Peer 1
Peer 2
Peer 3
Peer 4
Peer 5
Peer 6
Peer 7
Peer 8
AREX
Second Quarter 2015 Results –
August 2015
Source:
Company
presentations
and
public
filings,
peer
data
as
of
1Q15.
Peers
include
CPE,
CWEI,
EGN,
FANG,
LPI,
PE,
PXD,
and
RSPP.

8
AREX Flowback
and Produced Water Recycle Facility
•
2 MM Bbls
flowback
and
produced water recycled
since inception
Second Quarter 2015 Results –
August 2015

Strong, simple balance sheet
9
AREX Liquidity and Capitalization
•
At June 30, 2015, we had a $1 billion senior secured revolving
credit facility in place, with aggregate lender commitments of
$450 MM and borrowing base of $525 MM
•
Following the Spring 2015 redetermination, our lenders
reaffirmed the commitment amount of $450 MM, while
reducing the borrowing base to $525 MM
•
A $75 MM cushion remains against more conservative bank
lending framework
•
Manageable Debt / LTM EBITDAX of 3.1x
•
LTM EBITDAX / LTM Interest of 6.9x, well above minimum
2.5x covenant requirement
•
No near-term debt maturities
AREX Debt Maturity Schedule ($ MM)
AREX Capitalization as of 6/30/2015 ($ MM)
Cash
$0.8
Credit Facility
254.4
7.0% Senior Notes due 2021
244.7
Total Long-Term Debt 1
$499.1
Shareholders’ Equity
758.9
Total Book Capitalization
$1,258.0
AREX Liquidity as of 6/30/2015
Aggregate Commitment
$450.0
Cash and Cash Equivalents
0.8
Borrowings under Credit Facility
(257.0)
Undrawn Letters of Credit
(0.3)
Liquidity
$193.4
$257.0
$250.0
$0.0
$50.0
$100.0
$150.0
$200.0
$250.0
$300.0
$350.0
$400.0
$450.0
2015
2016
2017
2018
2019
2020
2021
$193 MM undrawn
borrowing capacity
7.0% Senior Notes
Second Quarter 2015 Results –
August 2015
1. Long-term debt is net of debt issuance costs of $7.9 million as of June 30, 2015

Valuation and leverage well supported by proved reserve base
10
•
12/31/2014 reserve summary prepared by DeGolyer
and MacNaughton
•
Replaced 819% of produced reserves at a drill-bit F&D cost of $8.94 per Boe
1
•
Total proved reserves up 27% YoY, proved oil reserves up 20% YoY
•
PV-10 up 25% YoY
to a record $1.4 billion
Oil (MBbls)
NGLs (MBbls)
Natural Gas (MMcf)
Total (MBoe)
PV-10 ($ MM)
2
PDP
17,599
18,319
133,583
58,181
$870.0
PDNP
379
763
5,378
2,039
$12.4
PUD
37,360
21,825
161,059
86,028
$530.6
Total Proved
55,338
40,907
300,020
146,248
$1,413.0
Total Proved Reserves
Reserves by Commodity
Proved PV-10
38%
28%
34%
Oil
NGLs
Natural Gas
40%
1%
59%
PDP
PDNP
PUD
62%
< 1%
38%
PDP
PDNP
PUD
1.
Drill-bit
F&D
costs
are
calculated
by
dividing
the
sum
of
exploration
costs
and
development
costs
for
the
year
by
the
total
of
reserve
extensions
and
discoveries
for
the
year.
2.
PV-10
calculated
based
on
the
first-of-the-month,
12-month
average
prices
for
oil,
NGLs
and
natural
gas,
of
$94.56
per
Bbl
of
oil,
$31.50
per
Bbl
of
NGLs
and
$4.55
per
MMBtu
of
natural
gas.
Second Quarter 2015 Results –
August 2015

D&C Cost reductions will significantly improve profitability
11
Note:
HZ
Wolfcamp
economics
assume
$4.00/Mcf
realized
natural
gas
price
and
NGL
price
based
on
40%
of
realized
oil
price.
0%
10%
20%
30%
40%
50%
60%
70%
$40
$50
$60
$70
$80
$90
Realized Oil Price ($/Bbl)
$4.0MM D&C
$4.5MM D&C
$5.0MM D&C
Second Quarter 2015 Results –
August 2015

Established infrastructure in place is critical to low cost
structure
12
Benefits of water recycling
•
Reduce D&C cost
•
Reduce LOE
•
Increase project profit margin
•
Minimize fresh water use, truck
traffic and surface disturbance
Pangea
West
North & Central Pangea
South
Pangea
Schleicher
Crockett
Irion
Reagan
Sutton
Recently completed
water recycling facility
329,000 Bbl
Capacity
Second Quarter 2015 Results –
August 2015

Current hedge position
13
Commodity
& Period
Contract Type
Volume
Contract Price
Crude
Oil
July
2015
–
December
2015
Collar
1,600 Bbls/d
$84.00/Bbl
-
$91.00/Bbl
July
2015
–
December
2015
Collar
1,000 Bbls/d
$90.00/Bbl
-
$102.50/Bbl
July
2015
–
December
2015
3-way Collar
500 Bbls/d
$75.00/Bbl
-
$84.00/Bbl
-
$94.00/Bbl
July
2015
–
December
2015
3-way Collar
500 Bbls/d
$75.00/Bbl
-
$84.00/Bbl
-
$95.00/Bbl
July
2015
–
December
2016
Swap
750 Bbls/d
$62.52/Bbl
Natural
Gas
July
2015
–
December
2015
Swap
200,000 MMBtu/month
$4.10/MMBtu
July
2015
–
December
2015
Collar
130,000 MMBtu/month
$4.00/MMBtu -
$4.25/MMBtu
•
Based
on
the
midpoint
of
updated
2015
guidance,
approximately
85%
of
forecasted
3Q15-4Q15
oil
production
and
32%
of
forecasted
natural
gas
production
are
hedged
at
weighted
average
floor
prices
of
$75.93/Bbl
and
$4.06/MMBtu,
respectively.
Second Quarter 2015 Results –
August 2015

Production and expense guidance
14
Updated 2015 Guidance
Production
Oil (MBbls)
1,900
–
1,975
NGLs (MBbls)
1,575
–
1,625
Natural
Gas (MMcf)
11,550
–
11,700
Total (MBoe)
5,400
–
5,550
Operating costs and expenses (per Boe)
Lease operating
$5.50 -
$6.50
Production and ad valorem taxes
7.50%
of oil & gas revenues
Cash general and administrative
$3.75 -
$4.25
Exploration (non-cash)
$0.50
-
$1.00
Depletion,
depreciation and amortization
$20.00 -
$22.00
Capital expenditures (in millions)
~$150
Second Quarter 2015 Results –
August 2015

Appendix

Adjusted net (loss) income (unaudited)
16
(in thousands, except per-share amounts)
Three Months Ended
June 30,
Six Months Ended
June 30,
2015
2014
2015
2014
Net (loss) income
$
(11,850)
$
3,793
$
(19,558)
$
6,738
Adjustments for certain items:
Unrealized loss on commodity derivatives
13,904
7,678
23,225
13,604
Rig termination fees
-
-
498
-
Related income tax effect
(4,866)
(2,780)
(8,303)
(4,934)
Adjusted net (loss) income
$
(2,812)
$
8,691
$
(4,138)
$
15,408
Adjusted net (loss) income per diluted share
$
(0.07)
$
0.22
$
(0.10)
$
0.39
The
amounts
included
in
the
calculation
of
adjusted
net
(loss)
income
and
adjusted
net
(loss)
income
per
diluted
share
below
were
computed
in
accordance
with
GAAP.
We
believe
adjusted
net
income
and
adjusted
net
income
per
diluted
share
are
useful
to
investors
because
they
provide
readers
with
a
more
meaningful
measure
of
our
profitability
before
recording
certain
items
whose
timing
or
amount
cannot
be
reasonably
determined.
However,
these
measures
are
provided
in
addition
to,
and
not
as
an
alternative
for,
and
should
be
read
in
conjunction
with,
the
information
contained
in
our
financial
statements
prepared
in
accordance
with
GAAP
(including
the
notes),
included
in
our
SEC
filings
and
posted
on
our
website.
The
following
table
provides
a
reconciliation
of
adjusted
net
(loss)
income
to
net
(loss)
income
for
the
three
and
six
months
ended
June
30,
2015
and
2014.
ADJUSTED NET (LOSS) INCOME (UNAUDITED)
Second Quarter 2015 Results –
August 2015

EBITDAX (unaudited)
17
EBITDAX (UNAUDITED)
The
amounts
included
in
the
calculation
of
EBITDAX
were
computed
in
accordance
with
GAAP.
EBITDAX
is
not
a
measure
of
net
income
or
cash
flow
as
determined
by
GAAP.
EBITDAX
is
presented
herein
and
reconciled
to
the
GAAP
measure
of
net
income
because
of
its
wide
acceptance
by
the
investment
community
as
a
financial
indicator
of
a
company's
ability
to
internally
fund
development
and
exploration
activities.
This
measure
is
provided
in
addition
to,
and
not
as
an
alternative
for,
and
should
be
read
in
conjunction
with,
the
information
contained
in
our
financial
statements
prepared
in
accordance
with
GAAP
(including
the
notes),
included
in
our
SEC
filings
and
posted
on
our
website.
The
following
table
provides
a
reconciliation
of
EBITDAX
to
net
(loss)
income
for
the
three
and
six
months
ended
June
30,
2015
and
2014.
(in thousands, except per-share amounts)
Three Months Ended
June 30,
Six Months Ended
June 30,
2015
2014
2015
2014
Net (loss) income
$
(11,850)
$
3,793
$
(19,558)
$
6,738
Exploration
1,165
1,966
2,255
2,704
Depletion, depreciation and amortization
28,404
28,573
54,924
52,179
Share-based
compensation
2,075
1,107
4,292
3,761
Unrealized loss on commodity derivatives
13,904
7,678
23,225
13,604
Interest expense, net
6,243
5,357
12,165
10,494
Income tax (benefit) provision
(7,369)
2,153
(11,365)
3,834
EBITDAX
$
32,572
$
50,627
$
65,938
$
93,314
EBITDAX per diluted share
$
0.80
$
1.29
$
1.63
$
2.37
Second Quarter 2015 Results –
August 2015

Cash operating expenses
18
Cash operating expenses
We
define
cash
operating
expenses
as
operating
expenses,
excluding
(1)
exploration
expense,
(2)
depletion,
depreciation
and
amortization
expense
and
(3)
share-based
compensation
expense.
Cash
operating
expenses
is
not
a
measure
of
operating
expenses
as
determined
by
GAAP.
The
amounts
included
in
the
calculation
of
cash
operating
expenses
were
computed
in
accordance
with
GAAP.
Cash
operating
expenses
is
presented
herein
and
reconciled
to
the
GAAP
measure
of
operating
expenses.
We
use
cash
operating
expenses
as
an
indicator
of
the
Company’s
ability
to
manage
its
operating
expenses
and
cash
flows.
This
measure
is
provided
in
addition
to,
and
not
as
an
alternative
for,
and
should
be
read
in
conjunction
with,
the
information
contained
in
our
financial
statements
prepared
in
accordance
with
GAAP
(including
the
notes),
included
in
our
SEC
filings
and
posted
on
our
website.
The
following
table
provides
a
reconciliation
of
cash
operating
expenses
to
operating
expenses
for
the
three
and
six
months
ended
June
30,
2015
and
2014.
(in thousands, except per-Boe
amounts)
Three Months Ended
June 30,
Six Months Ended
June 30,
2015
2014
2015
2014
Operating expenses
$
46,970
$
50,812
$
92,656
$
95,711
Exploration
(1,165)
(1,966)
(2,255)
(2,704)
Depletion, depreciation and amortization
(28,404)
(28,573)
(54,924)
(52,179)
Share-based
compensation
(2,075)
(1,107)
(4,292)
(3,761)
Cash operating expenses
$
15,326
$
19,166
$
31,185
$
37,067
Cash operating expenses per Boe
$
11.02
$
14.90
$
11.65
$
15.75
Second Quarter 2015 Results –
August 2015

F&D costs (unaudited)
19
F&D Cost reconciliation
Cost summary (in thousands)
Property acquisition costs
Unproved properties
$
4,578
Proved properties
-
Exploration
costs
3,831
Development costs
382,995
Total costs incurred
$
391,404
Reserves summary (MBoe)
Balance –
12/31/2013
114,661
Extensions & discoveries
43,247
Production (1)
(5,281)
Revisions to previous estimates
(6,379)
Balance –
12/31/2014
146,248
F&D cost
($/Boe)
All-in F&D cost
$
10.62
Drill-bit
F&D cost
8.94
Reserve replacement ratio
Drill-bit
819%
All-in
finding
and
development
(“F&D”)
costs
are
calculated
by
dividing
the
sum
of
property
acquisition
costs,
exploration
costs
and
development
costs
for
the
year
by
the
sum
of
reserve
extensions
and
discoveries,
purchases
of
minerals
in
place
and
total
revisions
for
the
year.
Drill-bit
F&D
costs
are
calculated
by
dividing
the
sum
of
exploration
costs
and
development
costs
for
the
year
by
the
total
of
reserve
extensions
and
discoveries
for
the
year.
We
believe
that
providing
F&D
cost
is
useful
to
assist
in
an
evaluation
of
how
much
it
costs
the
Company,
on
a
per
Boe
basis,
to
add
proved
reserves.
However,
these
measures
are
provided
in
addition
to,
and
not
as
an
alternative
for,
and
should
be
read
in
conjunction
with,
the
information
contained
in
our
financial
statements
prepared
in
accordance
with
GAAP
(including
the
notes),
included
in
our
previous
SEC
filings
and
to
be
included
in
our
annual
report
on
Form
10-K
to
be
filed
with
the
SEC
on
February
26,
2015.
Due
to
various
factors,
including
timing
differences,
F&D
costs
do
not
necessarily
reflect
precisely
the
costs
associated
with
particular
reserves.
For
example,
exploration
costs
may
be
recorded
in
periods
before
the
periods
in
which
related
increases
in
reserves
are
recorded,
and
development
costs
may
be
recorded
in
periods
after
the
periods
in
which
related
increases
in
reserves
are
recorded.
In
addition,
changes
in
commodity
prices
can
affect
the
magnitude
of
recorded
increases
(or
decreases)
in
reserves
independent
of
the
related
costs
of
such
increases.
As
a
result
of
the
above
factors
and
various
factors
that
could
materially
affect
the
timing
and
amounts
of
future
increases
in
reserves
and
the
timing
and
amounts
of
future
costs,
including
factors
disclosed
in
our
filings
with
the
SEC,
we
cannot
assure
you
that
the
Company’s
future
F&D
costs
will
not
differ
materially
from
those
set
forth
above.
Further,
the
methods
used
by
us
to
calculate
F&D
costs
may
differ
significantly
from
methods
used
by
other
companies
to
compute
similar
measures.
As
a
result,
our
F&D
costs
may
not
be
comparable
to
similar
measures
provided
by
other
companies.
The
following
table
reconciles
our
estimated
F&D
costs
for
2014
to
the
information
required
by
paragraphs
11
and
21
of
ASC
932-235.
(1)
Production
includes
1,390
MMcf
related
to
field
fuel.
Second Quarter 2015 Results –
August 2015

PV-10 (unaudited)
20
The
present
value
of
our
proved
reserves,
discounted
at
10%
(“PV-10”),was
estimated
at
$1.4
billion
at
December
31,
2014,
and
was
calculated
based
on
the
first-of-the-month,
twelve-month
average
prices
for
oil,
NGLs
and
gas,
of
$94.56
per
Bbl
of
oil,
$31.50
per
Bbl
of
NGLs
and
$4.55
per
MMBtu
of
natural
gas.
PV-10
is
our
estimate
of
the
present
value
of
future
net
revenues
from
proved
oil
and
gas
reserves
after
deducting
estimated
production
and
ad
valorem
taxes,
future
capital
costs
and
operating
expenses,
but
before
deducting
any
estimates
of
future
income
taxes.
The
estimated
future
net
revenues
are
discounted
at
an
annual
rate
of
10%
to
determine
their
“present
value.”
We
believe
PV-10
to
be
an
important
measure
for
evaluating
the
relative
significance
of
our
oil
and
gas
properties
and
that
the
presentation
of
the
non-GAAP
financial
measure
of
PV-10
provides
useful
information
to
investors
because
it
is
widely
used
by
professional
analysts
and
investors
in
evaluating
oil
and
gas
companies.
Because
there
are
many
unique
factors
that
can
impact
an
individual
company
when
estimating
the
amount
of
future
income
taxes
to
be
paid,
we
believe
the
use
of
a
pre-tax
measure
is
valuable
for
evaluating
the
Company.
We
believe
that
PV-10
is
a
financial
measure
routinely
used
and
calculated
similarly
by
other
companies
in
the
oil
and
gas
industry.
The
following
table
reconciles
PV-10
to
our
standardized
measure
of
discounted
future
net
cash
flows,
the
most
directly
comparable
measure
calculated
and
presented
in
accordance
with
GAAP.
PV-10
should
not
be
considered
as
an
alternative
to
the
standardized
measure
as
computed
under
GAAP.
(in millions)
December 31,
2014
PV-10
$
1,413
Less income taxes:
Undiscounted future income
taxes
(1,267)
10%
discount factor
910
Future discounted income taxes
(357)
Standardized
measure of discounted future net cash flows
$
1,056
Second Quarter 2015 Results –
August 2015

Contact information
SERGEI KRYLOV
Executive Vice President & Chief Financial Officer
817.989.9000
ir@approachresources.com
www.approachresources.com