Attached files
| file | filename |
|---|---|
| 8-K - FORM 8-K - Approach Resources Inc | d682365d8k.htm |
| EX-99.1 - EX-99.1 - Approach Resources Inc | d682365dex991.htm |
 Fourth Quarter & Full-Year
2013 Results
FEBRUARY 24, 2014
Exhibit 99.3 |
 Forward-looking statements
Fourth Quarter 2013 Results –
February 2014
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
AREX OVERVIEW
ASSET OVERVIEW
Enterprise value $1 BN
High-quality reserve base
115 MMBoe proved reserves
$1.1 BN proved PV-10
99% Permian Basin
Permian core operating area
163,000 gross (146,000 net) acres
~1+ BnBoe gross, unrisked resource potential
~2,000+ Identified HZ drilling locations targeting
Wolfcamp A/B/C
2014 Capital program of $400 MM
Running 3 HZ rigs in the Wolfcamp shale play to
drill 70 wells during 2014
Notes:
Proved
reserves
and
acreage
as
of
12/31/2013.
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
$20.65
per
share
on
2/21/2014,
plus
net
debt
as
of
12/31/2013.
See
“PV-10
(unaudited)”
slide.
3
Fourth Quarter 2013 Results –
February 2014 |
 Key investment highlights
Fourth Quarter 2013 Results –
February 2014
4
Low-Risk, Oil-Rich Asset Base
Oil and liquids-weighted asset base in Midland Basin
•
163,000 gross (146,000 net) primarily contiguous acres
•
Proved reserves are 69% liquids; 4Q13 production is 72% liquids
(46% 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 31% and 34%, respectively
Low-cost operator with competitive F&D and low lifting costs
•
2013 Drill bit F&D cost $10.63/Boe
•
4Q13 Lease operating expense of $5.19/Boe vs. $7.29/Boe (4Q12)
Strong Financial Position
Liquidity of $408 MM
Active hedging program
Accelerating Development, Reducing Well Costs
2014 Production growth target 40%
•
Drilling 55%+ more HZ wells with 3 rig program
Development D&C cost of $5.5 MM, working on further cost reductions
Note:
Estimated
acreage
and
proved
reserves
as
of
12/31/2013.
See
“Drill-bit
F&D
cost
(unaudited)”
and
“Strong,
simple
balance
sheet”
slides. |
 Strong track record of reserve growth
Fourth Quarter 2013 Results –
February 2014
5
RESERVE GROWTH
OIL RESERVE GROWTH
•
YE13 reserves up 20% YoY
•
Replaced 776% of reserves at a drill-bit F&D
cost of $10.63/Boe
•
81.6 MMBoe proved reserves booked to HZ
Wolfcamp play
•
Strong, organic oil reserve growth driven by
HZ Wolfcamp shale
•
Oil reserves up 11x
since YE09
•
Oil reserves up 24% YoY
Note:
See
“Drill-bit
F&D
cost
(unaudited)”
slide.
MMBoe
MMBbls |
 Proved reserves walk-forward
Fourth
Quarter
2013
Results
–
February
2014
6
YE13 PROVED RESERVES
•
Proved reserves increase 20% YoY
•
HZ Wolfcamp proved reserves increase 52% YoY
•
Proportion of proved developed reserves increased to 39%, up from 34% at YE12
95.5
114.7
MMBoe |
 Strong track record of production growth
Fourth Quarter 2013 Results –
February 2014
7
PRODUCTION GROWTH
OIL PRODUCTION GROWTH
•
2013 Production increased 19% YoY
•
Targeting 40% production growth in 2014
4,790 MBoe in 2014
2014E Production mix ~44.5% oil (72.5% total
liquids), based on midpoint of guidance
•
Strong, organic oil production growth driven
by HZ Wolfcamp shale
•
Oil production up 7x
since FY09
•
Oil production up 49% YoY
MBbls
MBoe/d |
 HZ
Wolfcamp proved reserves up 5x
since 2011
Horizontal Wolfcamp reserve growth driving oil production growth
Fourth Quarter 2013 Results –
February 2014
8
HZ WOLFCAMP RESERVE GROWTH
FY13 HZ WOLFCAMP PRODUCTION MIX
114.7
95.5
77.0
Began drilling
HZ Wolfcamp
MMBoe |
 4Q13 Operational Update |
 4Q13 Operating highlights
OPERATING HIGHLIGHTS
Driving Down
Costs
•
LOE of $5.19/Boe (down 29% YoY)
•
Oil differential of $(6.09)/Bbl (improved 38% YoY)
Delivering
Strong Well
Results &
Advancing
Delineation
•
4Q13 HZ Wolfcamp average IP 766 Boe/d
•
Transitioned Wolfcamp C to development mode and advanced understanding of
stacked wellbore development
•
Stacked Wolfcamp C in central Pangea IPs at 970 Boe/d (offsetting Wolfcamp B
wells with an average IP of 886 Boe/d)
•
HZ well results continue to track at or above type curve
Accelerating
Development
•
Completed 14 HZ
wells
•
Total production 11.3 MBoe/d (exceeded guidance)
•
4Q13 production 46% oil (up 59% YoY and 51% QoQ)
•
2014 production growth target 40%, made up of 43%-46%
oil Fourth Quarter 2013 Results –
February 2014
10 |
 AREX Wolfcamp shale oil resource play
Fourth Quarter 2013 Results –
February 2014
11
PERMIAN CORE OPERATING AREA
Large, primarily contiguous acreage position
Oil-rich, multiple pay zones
163,000 gross (146,000 net) acres
Low acreage cost ~$500 per acre
~2,000 Identified HZ Wolfcamp locations
Large, primarily contiguous acreage
position with oil-rich, multiple pay zones
2014
OPERATIONS
Plan to drill ~70 HZ wells with 3 rigs
~ 1BnBoe gross, unrisked HZ Wolfcamp
resource potential
Field infrastructure systems contributing to lower
LOE/Boe and HZ D&C costs
Compressing spud-to-sales times
Focusing activity around field infrastructure systems
Testing “stacked-wellbore”
development and
optimizing well spacing and completion design
Decreasing well costs and increasing efficiencies |
 AREX Wolfcamp activity
Fourth Quarter 2013 Results –
February 2014
12
NORTH &
CENTRAL PANGEA
SOUTH PANGEA
PANGEA WEST
Note: Acreage as of 12/31/2013.
•
19,000 gross acres
•
Pad drilling with AB and AC “stacked”
wellbores
Schleicher
Crockett
Irion
Reagan
•
55,000 gross acres
•
Continuing completion
design improvement
•
89,000 gross acres
•
Pad drilling with AB, AC, and BC “stacked”
wellbores
Sutton
Legend
Vertical Producer
¦
HZ Producer
¦
HZ –
Waiting on Completion
¦
HZ –
Drilling |
 AREX HZ Wolfcamp Well Performance
13
AREX HZ WOLFCAMP (BOE/D)
Fourth Quarter 2013 Results –
February 2014
Note: Daily production normalized for operational downtime.
Production Data from AREX
A Bench Wells (8)
450 MBoe Type Curve
Wolfcamp Shale Oil
Production Data from AREX
B Bench Wells (56)
Production Data from AREX C
Bench Wells (2) |
 AREX HZ Wolfcamp economics
14
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
~2,000
Gross Resource
Potential
~1 Bn
Boe
BTAX IRR SENSITIVITIES
•
Horizontal drilling improves recoveries and
returns
•
Targeting Wolfcamp A / B / C
•
7,000’+ lateral length
•
~80% of EUR made up of oil and NGLs
Fourth Quarter 2013 Results –
February 2014 |
   Infrastructure for large-scale development
Fourth Quarter 2013 Results –
February 2014
15
•
Reducing D&C cost
•
Reducing LOE
•
Increasing project profit margin
•
Minimizing truck traffic and surface
disturbance
Pangea
West
North & Central Pangea
South
Pangea
Schleicher
Crockett
Irion
Reagan
Sutton
50-Mile Oil Pipeline
100,000 Bbls/d
Capacity |
 Key field infrastructure & equipment systems
Fourth Quarter 2013 Results –
February 2014
16
•
Safely and securely transport water across Project Pangea and Pangea West
•
Reduce time and money spent on water hauling and disposal and also reduces
truck traffic
•
Replace rental equipment and contractors with Company-owned and operated
equipment and personnel; reduce money spent on flowback operations
•
Facilitate large-scale field development
•
Reduce fresh water use and water costs
Water transfer equipment
SWD wells
Gas lift system and flowback
equipment
Non-potable water source wells
Water recycling systems
BENEFITS
Infrastructure and equipment systems are key to large-scale field development
and to reducing D&C costs and LOE/Boe cost
INFRASTRUCTURE
•
First-mover oil pipeline system in the southern Midland Basin
•
50-mile pipeline with 100 MBoe/d throughput capacity
•
Sold in October 2013 for 6x ROI
•
Maintain competitive oil transportation fee and firm takeaway
Oil pipeline and marketing
agreements |
 4Q13 Financial update |
 4Q13 Financial highlights
FINANCIAL HIGHLIGHTS
Significant Cash
Flow
•
Record quarterly EBITDAX (non-GAAP) of $41.1 MM (up 99% YoY), or $1.05 per
diluted share (up 98% YoY)
•
Capital expenditures $74.9 MM
Strong Financial
Position
•
Liquidity
of
$408
MM
at
December
31
st
•
Undrawn borrowing base of $350 MM
•
26% Debt-to-capital ratio
Increasing
Revenues
•
Revenues of $58.6 MM (up 66% YoY)
•
Net income of $64.3 MM, or $1.65 per diluted share
•
Adjusted net income (non-GAAP) of $8 MM, or $0.20 per diluted share
Strong Balance Sheet and Liquidity to Develop
HZ Wolfcamp Shale
Note:
See
“Adjusted
Net
Income,”
“EBITDAX”
and
“Strong,
Simple
Balance
Sheet”
slides
in
appendix.
Fourth Quarter 2013 Results –
February 2014
18 |
 •
Oil production growth, lower costs generating margin improvement
•
4Q13 Total cash costs $17.18/Boe (9% lower than 4Q12)
•
Unhedged cash margin $39.09/Boe (50% higher than 4Q12)
Cash margin improvement
Fourth Quarter 2013 Results –
February 2014
19
4Q13 UNHEDGED CASH MARGIN ($/BOE) |
 Oil & liquids-weighted reserves, production & revenue
Fourth Quarter 2013 Results –
February 2014
20
YE13 RESERVE MIX
FY13 PRODUCTION MIX
FY14-E PRODUCTION MIX
FY13 REVENUE MIX
9.4
MBoe/d
13.1
MBoe/d
$181.3
MM
114.7
MMBoe
Based on midpoint of FY14 guidance. |
 Strong, simple balance sheet
Fourth Quarter 2013 Results –
February 2014
21
FINANCIAL RESULTS ($MM)
As of
12/31/2013
Summary Balance Sheet
Cash
$58.8
Credit Facility
–
Senior Notes
250.0
Total Long-Term Debt
$250.0
Shareholders’
Equity
710.5
Total Book Capitalization
$960.5
Liquidity
Borrowing Base
$350.0
Cash and Cash Equivalents
58.7
Long-term Debt under Credit Facility
–
Undrawn Letters of Credit
(0.3)
Liquidity
$408.4
Key Metrics
LTM EBITDAX
$127.8
Total Reserves (MMBoe)
114.7
Proved Developed Reserves (MMBoe)
45.2
% Proved Developed
39%
% Liquids
69%
Credit Statistics
Net Debt
Total Debt
Debt / Capital
20%
26%
Debt / 4Q13 Annualized EBITDAX
1.2x
1.5x
Debt / Proved Reserves ($/Boe)
$1.67
$2.18 |
 Current hedge position
Fourth Quarter 2013 Results –
February 2014
22
Commodity & Period
Contract Type
Volume
Contract Price
Crude Oil
January 2014 –
December 2014
Collar
550 Bbls/d
$90.00/Bbl -
$105.50/Bbl
January 2014 –
December 2014
Collar
950 Bbls/d
$85.05/Bbl -
$95.05/Bbl
January 2014 –
December 2014
Collar
2,000 Bbls/d
$89.00/Bbl -
$98.85/Bbl
April 2014 –
March 2015
Collar
1,500 Bbls/d
$85.00/Bbl -
$95.30/Bbl
January 2015 –
December 2015
Collar
2,600 Bbls/d
$84.00/Bbl -
$91.00/Bbl
Natural Gas Liquids
Propane
January 2014 –
December 2014
Swap
500 Bbls/d
$41.16/Bbl
Natural Gasoline
January 2014 –
December 2014
Swap
175 Bbls/d
$83.37/Bbl
Natural Gas
January 2014 –
December 2014
Swap
360,000 MMBtu/month
$4.18/MMBtu
February 2014 –
December 2014
Swap
35,000 MMBtu/month
$4.29/MMBtu
March 2014 –
December 2014
Swap
160,000 MMBtu/month
$4.40/MMBtu
September 2014 –
June 2015
Collar
80,000 MMBtu/month
$4.00/MMBtu -
$4.74/MMBtu
January 2015 –
December 2015
Swap
200,000 MMBtu/month
$4.10/MMBtu
January 2015 –
December 2015
Collar
130,000 MMBtu/month
$4.00/MMBtu -
$4.25/MMBtu |
 Production and expense guidance
Fourth Quarter 2013 Results –
February 2014
23
2014 Guidance
Production
Total (MBoe)
4,790
Percent oil
43% -
46%
Percent total liquids
71% -
74%
Operating costs and expenses (per Boe)
Lease operating
$5.00 -
$6.00
Production and ad valorem taxes
7.25% of oil & gas revenues
Cash general and administrative
$4.50 -
$5.00
Exploration
$0.50 -
$1.00
Depletion, depreciation and amortization
$22.00 -
$24.00
Capital expenditures (in millions)
Approx. $400
Horizontal wells
70 |
 Adjusted net income (unaudited)
Fourth Quarter 2013 Results –
February 2014
24
(in thousands, except per-share amounts)
Three Months Ended
December 31,
2013
2012
Net income (loss)
$
64,321
$
(837)
Adjustments for certain items:
Unrealized loss (gain) on commodity derivatives
1,348
(1,292)
Gain on sale of equity method investment
(90,743)
—
Related income tax effect
33,076
439
Adjusted net income (loss)
$
8,002
$
(1,690)
Adjusted net income (loss) per diluted share
$
0.20
$
(0.04)
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
income
(loss)
for
the
three
months
ended
December
31,
2013
and
2012. |
 EBITDAX (unaudited)
Fourth Quarter 2013 Results –
February 2014
25
We
define
EBITDAX
as
net
income
(loss),
plus
(1)
exploration
expense,
(2)
gain
on
the
sale
of
our
equity
method
investment,
(3)
depletion,
depreciation
and
amortization
expense,
(4)
share-based
compensation
expense,
(5)
unrealized
loss
(gain)
on
commodity
derivatives,
(6)
interest
expense
and
(7)
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
ourwebsite.
The
following
table
provides
a
reconciliation
of
EBITDAX
to
net
income
(loss)
for
the
three
months
ended
December
31,
2013
and
2012.
(in thousands, except per-share amounts)
Three Months Ended
December 31,
2013
2012
Net income (loss)
$
64,321
$
(837)
Exploration
228
2,131
Gain on sale of equity method investment
(90,743)
—
Depletion, depreciation and amortization
22,005
18,027
Share-based compensation
512
2,472
Unrealized loss (gain) on commodity derivatives
1,348
(1,292)
Interest expense, net
5,225
926
Income tax provision (benefit)
38,207
(781)
EBITDAX
$
41,103
$
20,646
EBITDAX per diluted share
$
1.05
$
0.53 |
 F&D costs (unaudited)
Fourth Quarter 2013 Results –
February 2014
26
F&D Cost reconciliation
Cost summary (in thousands)
Property acquisition costs
Unproved properties
$
5,857
Proved properties
1,000
Exploration costs
2,238
Development costs
287,898
Total costs incurred
$
296,993
Reserves summary (MBoe)
Balance –
12/31/2012
95,479
Extensions & discoveries
27,282
Acquisition
109
Production (1)
(3,517)
Revisions to previous estimates
(4,692)
Balance –
12/31/2013
114,661
F&D cost ($/Boe)
All-in F&D cost
$
13.08
Drill-bit F&D cost
10.63
Reserve replacement ratio
Drill-bit
776%
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
or
before
March
3,
2014.
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
2013
to
the
information
required
by
paragraphs
11
and
21
of
ASC
932-235.
(1) Production includes 560 MMcf related to field fuel.
|
 PV-10 (unaudited)
Fourth Quarter 2013 Results –
February 2014
27
The
present
value
of
our
proved
reserves,
discounted
at
10%
(“PV-10”),
was
estimated
at
$1.1
billion
at
December
31,
2013,
and
was
calculated
based
on
the
first-of-the-month,
twelve-month
average
prices
for
oil,
NGLs
and
gas,
of
$97.28
per
Bbl
of
oil,
$30.16
per
Bbl
of
NGLs
and
$3.66
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
accord-
ance with
GAAP.
PV-10
should
not
be
considered
as
an
alternative
to
the
standardized
measure
as
computed
under
GAAP.
(in millions)
December 31,
2013
PV-10
$
1,132
Less income taxes:
Undiscounted future income taxes
(919)
10% discount factor
463
Future discounted income taxes
(456)
Standardized measure of discounted future net cash flows
$
676 |
 Contact information
MEGAN P. HAYS
Director, Investor Relations & Corporate Communications
817.989.9000
mhays@approachresources.com
www.approachresources.com |