Attached files
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| 8-K - FORM 8-K - Approach Resources Inc | d602251d8k.htm |
 Approach Resources Inc.
INVESTOR PRESENTATION
SEPTEMBER 2013
Exhibit 99.1 |
 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
ongoing
drilling
program,
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
very
limited
production
experience
with
these
projects,
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
|
 Company Overview
•
Enterprise value $1.2 BN
•
High quality reserve base
95.5 MMBoe proved reserves
99% Permian Basin
•
Permian core operating area
170,000 gross (152,000 net) acres
1+ BnBoe gross, unrisked resource
potential
2,000+ Identified HZ drilling locations
targeting the Wolfcamp A/B/C
•
2013 capital program of $260 MM
Running 3 HZ rigs in the Wolfcamp shale
play
Targeting 25%+ production growth
3
AREX OVERVIEW
ASSET OVERVIEW
Notes: Proved reserves and acreage as of 12/31/2012 and 6/30/2013, respectively.
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
$24.62
per
share
on
9/11/2013,
plus
net
debt
as
of
6/30/2013. |
 Key Investment Highlights
•
Low-Risk, Oil-Rich Asset Base
•
Oil and liquids-weighted asset base in Midland Basin
170,000 gross (152,000 net) primarily contiguous acres
Proved reserves are 69% liquids; 2Q13 production is 70% liquids (42% oil)
•
High Degree of Operational Control
•
Operate 100% reserve base with ~100% working interest
•
Track Record of Growth at Competitive Cost
•
Reserve and production CAGR since 2004 of 32% and 35% respectively
•
Low-cost operator with competitive F&D and low lifting costs
2Q13 lease operating expense of $4.89/Boe vs. $7.14/Boe (1Q13) and $6.03/Boe
(2Q12) •
Prudent Financial Management
•
Active hedging program
•
Substantial liquidity of $370 MM as of 6/30/2013
•
Recent agreement to monetize pipeline further strengthens liquidity
•
Experienced Management
•
Over 150 years of combined industry experience for senior management team
•
Strong operational track record in Permian Basin
•
Significant technical expertise
4
Note:
Estimated
proved
reserves
and
acreage
as
of
12/31/2012
and
6/30/2013,
respectively.
See
“Strong,
Simple
Balance
Sheet”
slide. |
 Oil Pipeline Monetization
First-mover oil pipeline system in the southern
Midland Basin
Formed Wildcat JV to develop pipeline system in
September 2012
50-miles of high-pressure, steel pipeline with
throughput capacity of 100,000 Bbls/d
Pipeline operational in April 2013
Announced sale of pipeline system on
September 19
th
AREX proceeds of $108 MM from pipeline sale
Total transaction value $210 MM
AREX capital contributions to pipeline system of
$16.3 MM as of June 30, 2013
6.6x ROI
Proceeds further strengthen liquidity position
Maintain competitive oil transportation fee and firm
takeaway
Oil transportation differential outlook $2.50/Bbl –
$4.00/Bbl
5
TRANSACTION OVERVIEW
WILDCAT OIL PIPELINE SYSTEM
Notes: AREX proceeds are before tax; AREX proceeds and transaction value subject to
customary post-closing conditions, adjustments and escrows. Crockett
Midway Truck
Station
Reagan
Irion
Schleicher |
 Strong Track Record of Reserve Growth…
6
RESERVE GROWTH
OIL RESERVE GROWTH
•
YE’12 reserves up 24% YoY
•
60.1 MMBoe proved reserves booked to
Wolfcamp/Wolffork oil shale play
•
Strong organic reserve growth driven by oil
from HZ Wolfcamp shale
•
Oil reserves up 7x
since YE’09
•
Oil reserves up 106%
YoY
PD Oil reserves up 60%
YoY
Launched
Wolfcamp Study
Announced
Vertical Wolfcamp
Pilot Results
Began HZ
Wolfcamp Pilot
Program
Strong HZ Wolfcamp Results;
Prepare for Large-Scale
Development |
 …and Production Growth
7
PRODUCTION GROWTH
OIL PRODUCTION GROWTH
•
2012 production increased 24% YoY
•
Targeting 25%+ production growth in 2013
•
Strong organic production growth driven by
oil from HZ Wolfcamp shale
•
Oil production up 4x
since 2009
•
Oil production up 101%
over 2011 |
 Oil & Liquids-Weighted Reserves, Production & Revenue
8
YE12 RESERVE MIX BY COMMODITY
2Q13 PRODUCTION MIX BY COMMODITY
2Q13 REVENUE MIX BY COMMODITY |
 AREX Wolfcamp Oil Shale Resource Play
9
Plan to complete ~40 to 42 HZ wells with 3 rigs
Testing “stacked-wellbore”
development and
optimizing well spacing and completion
design
Decrease well costs and increase efficiencies
when field infrastructure projects are
completed
Well costs within 5% of target HZ D&C cost of
$5.5 MM per well
PERMIAN CORE OPERATING AREA
2013 OPERATIONS
Large, primarily contiguous acreage
position with oil-rich, multiple pay zones
Large, primarily contiguous acreage position
Oil-rich, multiple pay zones
170,000 gross (152,000 net) acres
Low acreage cost ~$500 per acre
940+ MMBoe gross, unrisked HZ Wolfcamp
resource potential
2,096 Identified HZ Wolfcamp locations targeting the
Wolfcamp A, B & C |
 Wolfcamp Oil Shale Play
10
WOLFCAMP SHALE –
WIDESPREAD, THICK, CONSISTENT & REPEATABLE |
 Wolfcamp Stacked Pay Zones
11
Notes: Identified locations based on multi-bench development and 120-acre
spacing. No locations assigned to south Project Pangea. |
 AREX HZ Wolfcamp Activity
12
Notes: Acreage as of 6/30/2013.
Schleicher
Crockett
Irion
Reagan
Sutton
Legend
Vertical Producer
HZ Producer
HZ –
Waiting on Completion
HZ –
Drilling
HZ –
Permit
54-9 1
54-2 1
54-9 2
54-12 1
54-15 1
54-15 2
54-16 3
55-21 2
54-19 3
54-8 1
54-13 1
56-6 1
56-15 1
PW 6601H
PW 6602H
CT L 1801
54-13 2
54-20 2
54-20 1
55-21 3
56-14 1
PW 6507H
Chandler 4403
Childress 603
Childress G 1008
Lauffer 1306
Davidson 3406
Bailey 315
CT B 1601
CT M 901H
Baker B 203
CT B 1303
45 C 803H ST
42-11 2R
45 E 1101H
Baker C 1201
45 A 701H
45 B 2401H
45 F 2303H
CT B 1308
42-23 9
Baker A 114
West 2308
42-23 11
42-14 10
42 A 2101H
42-15 2
42 B 1001H
45 D 902H
CT A 807
45 A 703H
45 B 2402H
CT J 1001
CT G 1001
CT H 1001
West A 2210
42-11 3
CT J 1003H
42 C 101H
CT H 1002
CT G 701H
45 B 2403H
45 D 917H
CT K 1901
CT K 1902
45 D 904H
45 E 1102H
Baker B 207H
Baker B 206H
CT H 1004H
PW 6533H
PW 6535H
45 F 2304H
45 A 706H
45A 708H
45A 710H
45A 712H
Elliott 2002HB
CT M 902
U 50 A 603HA
CT L 6101H
45 C 839H
45 D 907H
45 D 905H
45 D 919H
45 D 913H
45 D 923H
45 D 927H
45D 931H
45 D 933H
45 D 903H
Baker B 256H
PW 6502H
PW 6504H
Elliott 2001HB
PANGEA WEST
19,000 gross acres
NORTH & CENTRAL
PANGEA
92,000 gross acres
SOUTH PANGEA
59,000 gross acres
•
3-D seismic acquisition & data
processing complete
•
3-D seismic interpretation in progress
•
3-D seismic interpretation complete
•
HZ pilot wells WOC (expect to
complete during 3Q13) |
 Accelerating Wolfcamp Program with 3 Rigs
13
Expect to drill ~20 to 24 HZ
wells per rig in 2014
vs. prior estimate of 10 to 12 HZ wells per rig
3 HZ rigs currently running in Project Pangea /
Pangea West
Recently drilled 2 wells in 10 to 11 days
(~7,500’
lateral)
Compressing spud-to-sales times
Focusing activity around field infrastructure
systems
Field infrastructure systems beginning to
contribute to lower LOE/Boe
OPERATIONAL EFFICIENCY
2013 COMPLETION ACTIVITY
COMPETITIVE LOE ($/Boe)
Notes: Oil-weighted peer companies include CXO, EOG, FANG, KOG, LPI, OAS, PXD
and ROSE. Lease operating expenses based on SEC filings for three
months ended June 30, 2013. 5
7
12-14
15-17
40-42
35-40
(Prior
Estimate) |
 HZ
Wolfcamp Well Performance 14
CONTINUED STRONG WELL RESULTS & MORE PRODUCTION HISTORY –
TRACKING
ABOVE THE TYPE CURVE
Time (Days)
0
100
200
300
400
500
600
700
800
900
1,000
1,100
1,200
0
90
180
270
360
450
540
630
720 |
 AREX HZ Wolfcamp Economics
15
Notes:
Identified
locations
based
on
multi-bench
development
and
120-acre
spacing
for
HZ
Wolfcamp.
No
locations
assigned
to
south
Project
Pangea.
HZ
Wolfcamp
economics
assume
NYMEX
–
Henry
Hub
strip
and
NGL
price
based
on
40%
of
WTI.
Play Type
Horizontal
Wolfcamp
Avg. EUR (gross)
450 MBoe
Targeted Well Cost
$5.5 MM
Potential Locations
2,096
Gross Resource
Potential
940+ MMBoe
BTAX IRR SENSITIVITIES
•
Horizontal drilling improves recoveries and
returns
•
Multiple, stacked horizontal targets
•
7,000’+ lateral length
•
~80% of EUR made up of oil and NGLs |
 AREX Drilling Locations, Targets & Resource Potential
16
Notes: Potential locations based on 120-acre spacing for HZ Wolfcamp,
20-acre spacing for Vertical Wolffork, 20 to 40-acre spacing for Vertical Wolffork
Recompletions and 40-acre spacing for Vertical Canyon Wolffork. No Wolfcamp or
Wolffork locations assigned to south Project Pangea. TARGET
DRLLING
DEPTH (FT.)
EUR
(MBoe)
IDENTIFIED
LOCATIONS
GROSS
RESOURCE
POTENTIAL
Horizontal
Wolfcamp
Wolfcamp A
7,000+
(lateral length)
450
703
316,350
Wolfcamp B
7,000+
(lateral length)
450
690
310,500
Wolfcamp C
7,000+
(lateral length)
450
703
316,350
Total HZ
2,096
943,200
Vertical
Wolffork
Recompletions,
Wolffork &
Canyon Wolffork
< 7,500 to
< 8,500
93 to 193
887
124,594
1.1 BnBoe Total Gross Resource Potential
Multiple Decades of HZ Drilling Inventory |
 Infrastructure for Large-Scale Development
17
•
Reducing D&C cost to $5.5 MM and lower
•
Reducing LOE
•
Minimizing truck traffic and surface disturbance
•
Increasing project profit margin
Pangea
West
North & Central Pangea
South
Pangea
Schleicher
Crockett
Irion
Reagan
Sutton
50-Mile Oil Pipeline
100,000 Bbls/d
Capacity |
 Infrastructure & Equipment Projects
18
•
Safely and securely transport water across Project Pangea and Pangea West
•
Reduce time and money spent on water hauling and disposal and truck traffic
•
Expected savings from water transfer equipment ~$0.1 MM/HZ well
•
Expected savings from SWD system ~$0.45 MM/HZ well
•
Expected company-wide LOE savings ±$0.4 MM per month
•
Replace rental equipment and contractors with Company-owned and operated
equipment and personnel; reduce money spent on flowback operations
•
Expected savings from flowback equipment ~$0.1 MM/HZ well
•
Expected LOE savings from gas lift system $6,300/HZ per month
•
Facilitate large-scale field development
•
Reduce fresh water use and water costs
•
Expected savings from non-potable water source ~$0.45 MM/HZ well
•
Efficiently transport crude oil to market and reduce inventory
•
Reduce oil transportation differential to an estimated $2.50/Bbl
–
$4.00/Bbl
Purchasing and installing water
transfer equipment
Drilling and/or converting SWD
wells
Purchasing and installing flowback
equipment
Securing water supply
Testing non-potable water and
recycling flowback water
Installing crude takeaway lines
Purchased oil hauling trucks
BENEFITS
Infrastructure and equipment projects are key to large-scale field development
and to reducing D&C costs as well as LOE cost
PROJECTS |
 Creating Value Through Growth
•
Concentrated geographic footprint in the Midland Basin
•
Strong growth track record at competitive costs
•
Detailed technical evaluation led to discovery of growth potential in the
Wolfcamp oil shale resource play
•
Rigorous pilot program de-risked ~107,000 gross acres
•
2013 Focus
Reducing HZ D&C costs to $5.5 MM and lower
Testing multi-bench “stacked”
laterals and closer well spacing
Transition to full-field development
19 |
 Financial
Information
NON-GAAP RECONCILIATIONS |
 2Q13 Operating & Financial Highlights
21
Increasing
Revenues and
Lower Costs
•
Revenues of $42.3 MM (up 41% YoY)
•
Total costs and expenses of $38.35/Boe (down 9% QoQ and stable YoY)
•
Net income of $7.8 MM or $0.20 per diluted share
•
Adjusted net income (non-GAAP) of $5 MM or $0.13 per diluted share
Significant Cash
Flow
•
EBITDAX (non-GAAP) of $30.7 MM (up 53% YoY) or $0.79 per diluted
share (up 32% YoY)
•
Cash flow from operations of $44.8 MM for the 1H’13
Strong Financial
Position
•
Liquidity of $370 MM
•
Undrawn borrowing base of $315 MM
•
During 2Q13, issued $250 million of 7% senior notes due 2021
HIGHLIGHTS
Notes:
See
“Adjusted
Net
Income,”
“EBITDAX”
and
“Strong,
Simple
Balance
Sheet”
slides
in
appendix.
Growing Oil
Production
•
Total production increased to 9 Mboe/d (up 16% YoY)
•
Oil growing as a percentage of production (up 50% YoY)
•
Targeting 28 to 30 HZ well completions during 2H’13
|
 2013 Capital Budget
•
2013 Capital budget $260 MM, approx. 90% for HZ Wolfcamp
•
3 HZ rigs in the Wolfcamp shale
•
Targeting Wolfcamp A, B and C
•
Testing “stacked-wellbore”
development
•
Optimizing well spacing and completion design
•
Targeting 25%+ production growth
•
2013
Production
guidance
3.6
MMBoe
–
3.9
MMBoe
•
2013E Production mix 70% liquids
Key takeaways:
2013 capital program provides flexibility to develop Wolfcamp oil shale and
monitor commodity prices and service costs
Increase in oil production drives expected increase in cash flow
Senior notes issuance, undrawn borrowing base and pipeline sale strengthen
liquidity 22 |
 Strong, Simple Balance Sheet
23
FINANCIAL RESULTS ($MM)
As of 6/30/2013
Summary Balance Sheet
Cash
$55.3
Credit Facility
–
Senior Notes
250.0
Total Long-Term Debt
$250.0
Shareholders’
Equity
644.3
Total Book Capitalization
$894.3
Liquidity
Borrowing Base
$315.0
Cash and Cash Equivalents
55.3
Long-term Debt under Credit Facility
–
Undrawn Letters of Credit
(0.3)
Liquidity
$370.0
Key Metrics
LTM EBITDAX
$97.2
Total Reserves (MMBoe)
95.5
Proved Developed Reserves (MMBoe)
32.8
% Proved Developed
34%
% Liquids
69%
Credit Statistics
Total Debt
Net Debt
Debt / Capital
28%
22%
Debt / 2Q13 Annualized EBITDAX
2.0x
1.6x
Debt / Proved Reserves ($/Boe)
$2.62
$2.04
Notes: Pipeline monetization proceeds are before taxes and subject to customary
post-closing conditions, adjustments and escrows. Estimated
proved
reserves
as
of
12/31/2012.
EBITDAX
is
a
non-GAAP
financial
measure.
See
“EBITDAX”
slide
and
website
for
reconciliation.
Net
debt
is debt balance less available cash and letters of credit.
Strong Balance Sheet and Liquidity to Develop HZ Wolfcamp Shale
•
Pipeline monetization proceeds of $108 MM further strengthen liquidity
|
 Current Hedge Position
24
Commodity and Time Period
Type
Volume
Price
Crude Oil
2013
Collar
650 Bbls/d
$90.00/Bbl -
$105.80/Bbl
2013
Collar
450 Bbls/d
$90.00/Bbl -
$101.45/Bbl
Feb –
Dec 2013
Collar
1,200 Bbls/d
$90.35/Bbl -
$100.35/Bbl
2014
Collar
550 Bbls/d
$90.00/Bbl -
$105.50/Bbl
2014
Collar
950 Bbls/d
$85.05/Bbl -
$95.05/Bbl
2015
Collar
2,600 Bbls/d
$84.00/Bbl -
$91.00/Bbl
Crude Oil Basis Differential (Midland/Cushing)
Mar –
Dec 2013
Swap
2,300 Bbls/d
$1.10/Bbl
2014
Swap
1,500 Bbls/d
$0.55/Bbl
Natural Gas Liquids
Propane Sept –
Dec 2013
Swap
550 Bbls/d
$42.00/Bbl
Propane 2014
Swap
500 Bbls/d
$41.16/Bbl
Natural Gasoline Sept –
Dec 2013
Swap
200 Bbls/d
$90.72/Bbl
Natural Gasoline 2014
Swap
175 Bbls/d
$83.37/Bbl
Natural Gas
2013
Swap
200,000 MMBtu/month
$3.54/MMBtu
2013
Swap
190,000 MMBtu/month
$3.80/MMBtu
May –
Dec 2013
Collar
100,000 MMBtu/month
$4.00/MMBtu -
$4.36/MMBtu
2014
Swap
360,000 MMBtu/month
$4.18/MMBtu |
 2013 Operating and Financial Guidance
25
Full-Year 2013
Guidance
Production
Total (MBoe)
3,600 –
3,900
Percent Oil & NGLs
70%
Operating costs and expenses ($/per Boe)
Lease operating
$
7.00 –
8.00
Production and ad valorem taxes
$
3.00 –
4.50
Exploration
$
2.00 –
3.00
General and administrative
$
7.00 –
8.50
Depletion, depreciation and amortization
$
20.00 –
24.00
Capital expenditures ($MM)
Approximately $260
•
3Q13
Production
guidance
8.7
MBoe/d
–
9
MBoe/d
•
3Q13
Exploration
expense
guidance
$6.00/Boe
–
$7.00/Boe
Our 2013 capital budget excludes acquisitions, lease extensions and equity
contributions to our pipeline joint venture, and is subject to change depending upon a
number of
factors, including additional data on our Wolfcamp shale oil resource play, results
of horizontal and vertical drilling, completions and recompletions,
including pad drilling, economic and industry conditions at the time of drilling,
prevailing and anticipated prices for oil, NGLs and gas, the availability of sufficient
capital resources for drilling prospects, our financial results and the
availability of lease extensions and renewals on reasonable terms. |
 Adjusted Net Income (unaudited)
26
The
amounts
included
in
the
calculation
of
adjusted
net
income
and
adjusted
net
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
income
to
net
(loss)
income
for
the
three
months
ended
June
30,
2013
and
2012,
respectively.
(in thousands, except per-share amounts)
Three Months Ended
June 30,
2013
2012
Net income
$
7,787
$
7,862
Adjustments for certain items:
Unrealized gain on commodity derivatives
(4,290)
(9,439)
Related income tax effect
1,459
3,209
Adjusted net income
$
4,956
$
1,632
Adjusted net income per diluted share
$
0.13
$
0.05 |
 EBITDAX (unaudited)
27
We
define
EBITDAX
as
net
income,
plus
(1)
exploration
expense,
(2)
depletion,
depreciation
and
amortization
expense,
(3)
share-based
compensation
expense,
(4)
unrealized
gain
on
commodity
derivatives,
(5)
interest
expense
and
(6)
income
taxes.
EBITDAX
is
not
a
measure
of
net
income
or
cash
flow
as
determined
by
GAAP.
The
amounts
included
in
the
calculation
of
EBITDAX
were
computed
in
accordance
with
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
income
for
the
three
months
ended
June
30,
2013
and
2012,
respectively.
(in thousands, except per-share amounts)
Three Months Ended
June 30,
2013
2012
Net income
$
7,787
$
7,862
Exploration
557
(38)
Depletion, depreciation and amortization
18,482
14,596
Share-based compensation
1,533
1,311
Unrealized gain on commodity derivatives
(4,290)
(9,439)
Interest expense, net
2,451
1,380
Income tax provision
4,217
4,390
EBITDAX
$
30,737
$
20,062
EBITDAX per diluted share
$
0.79
$
0.60 |
 Contact
Information
MEGAN P. HAYS
Manager, Investor Relations & Corporate Communications
817.989.9000 x2108
mhays@approachresources.com
www.approachresources.com |