Approach Resources Inc - FORM 8-K - EX-99.1 - INVESTOR PRESENTATION - January 12, 2012

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Approach Resources Inc.
Investor Presentation
JANUARY 12, 2012
Exhibit 99.1

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APPROACH RESOURCES
Forward-Looking Statements
Cautionary Statements Regarding Oil & Gas Quantities
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 Wolffork shale resource play, estimated oil and gas in place and recoverability of the oil and gas, estimated reserves and
drilling locations, capital expenditures, typical well results and well profiles, 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 Annual Report on Form
10-K for the year ended December 31, 2010, and the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2011.  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,” “upside,” “oil and gas in place” or “OGIP,” “OIP” or “GIP,” 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, potential drilling locations, resource potential and OGIP 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, including geological and mechanical factors affecting recovery rates.  Estimates of unproved reserves,
type/decline curves, per well EUR, OGIP and resource potential may change significantly as development of the Company’s oil and gas assets provides additional data.
 
Type/decline curves, estimated EURs, typical well-related oil and gas in place, 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, OGIP, 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, EURs and OGIP 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 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.
 

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APPROACH RESOURCES
Company Overview
Notes:
Proved
reserves
and
acreage
as
of
6/30/2011
and
9/30/2011,
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
$29.41
per
share
on
12/30/2011,
plus
net
debt
as
of
9/30/2011.
See
liquidity
calculation
in
appendix.
AREX OVERVIEW
ASSET OVERVIEW
•
Enterprise value $958 MM
•
High quality reserve base
•
Permian core operating area
160,600 gross (142,000 net) acres
500+ MMBoe gross, unrisked resource
potential
Extensive inventory of drilling and
recompletion opportunities
•
Strong balance sheet to execute plan
Borrowing base increased 30% to $260 MM
from $200 MM
66.8 MMBoe proved reserves
97% Permian Basin
55% Oil & NGLs
Pro forma liquidity of $260 MM at 9/30/2011

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APPROACH RESOURCES
Notes: Oil weighted peers include BRY, CXO, KOG, NOG, OAS, SD. Data based on SEC filings and J.S. Herold data. Lifting costs defined as lease operating expense plus taxes other than
income and gathering and transportation expense. See F&D cost reconciliation page in appendix for reconciliation of 3-year F&D costs.
Historical Results and Cost Structure
RESERVE GROWTH
3-YEAR AVERAGE F&D COSTS ($/BOE)
PRODUCTION GROWTH
3Q’11 LIFTING COSTS ($/BOE)
$8.78
$12.21
$13.29
$15.60
$16.95
$17.22
$20.96
AREX
Peer 1
Peer 2
Peer 3
Peer 4
Peer 5
Peer 6
$0
$5
$10
$15
$20
$25
$8.14
$9.73
$12.60
$13.32
$15.69
$17.88
$20.95
$0
$5
$10
$15
$20
$25
AREX
Peer 1
Peer 2
Peer 3
Peer 4
Peer 5
Peer 6
0%
10%
20%
30%
40%
50%
60%
2007
2008
2009
2010
9/30/2011
0%
10%
20%
30%
40%
50%
60%
2007
2008
2009
2010
6/30/2011
natural gas
oil & ngls
percent liquids
natural gas
oil & ngls
percent liquids
0
10
20
30
40
50
60
70
80
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0

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APPROACH RESOURCES
•
46.4 MMBoe proved reserves
•
4.5 MBoe/d daily production
•
98,000 net acres in Permian Basin
THEN…NOVEMBER 2010
NOW…2011 ACCOMPLISHMENTS
•
66.8 MMBoe proved reserves (+44% YoY)
•
6.7 MBoe/d daily production (+46% YoY)
•
142,000 net acres in Permian Basin (+45% YoY)
•
50% of proved reserves were liquids
•
34% of production were liquids
•
55% of proved reserves are liquids
•
57% of production is liquids
•
3 recompletions and 1 vertical well
commingled in Wolffork oil shale
resource play
•
11 recompletions and 10 vertical wells
completed through 10/30/11
•
7 horizontal Wolfcamp wells completed with 3
recent
IPs
ranging
798
–
1,044
Boe/d
•
Approach’s early view on the play has been
validated by the industry
•
$150 MM borrowing base
•
$173 MM pro forma liquidity
•
Q3 2010 EBITDAX of $12 MM
•
$260 MM borrowing base
•
$260 MM pro forma liquidity
•
Q3 2011 EBITDAX of $22 MM (+83% YoY)
Note:  See EBITDAX reconciliation and liquidity calculation in appendix.
2011 –
A Transformational Year for AREX
Growth
Reserves /
production mix
Financial
strength
Derisking
Wolffork play

APPROACH RESOURCES
Wolffork Oil Shale
Resource Play
PLAY IDENTIFICATION

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APPROACH RESOURCES
AREX Acreage Position –
Favorably Located in the Midland Basin

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APPROACH RESOURCES
Wolfcamp
Shale
Name
Convention
–
Southern
Midland
Basin
Wolfcamp shale name conventions are based on investor presentations of AREX (10/18/2010), EP (5/24/2011) and PXD (9/7/2011).

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APPROACH RESOURCES
•
Thermal Maturity:
Wolfcamp Rock Characteristics
OIL
.6
.9
1.20
1.35
2.0
3.0
Peak
Wet
Gas
Dry
Gas
Peak
Oil Floor
Wet Gas Floor
Dry Gas Floor
R
R
0
0
Baker A112
Wolfcamp R
0
~0.95-0.97
Richness
Good -
Excellent
Fair
TOC (%)
2-10
1-2
<1
Poor
2.24% –
7.24%
Natural
Fractures
Organic
material
Quartz and
carbonate
materials
Commonly
observed core
porosity values
for established
commercial
shale plays
0.0
2.0
4.0
6.0
8.0
10.0
12.0
Core porosity for Baker A 112:
Fractures
Absorption
WORLD CLASS SOURCE ROCK IN OIL WINDOW
SIGNIFICANT OIL & GAS STORAGE SPACE
•
TOC for Wolfcamp Shale from whole core of Baker A 112:
Oil & gas storage criteria for shales:
•
Matrix pore space
•
Fractures
•
Adsorption
Wolfcamp Shale:
-------------------------------------------------------------

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APPROACH RESOURCES
Wolfcamp Rock Characteristics
HYDROCARBON PATHWAY TO WELLBORE
WOLFCAMP SHALE COMPONENTS
Proximity to Ouachita-Marathon
thrust belt and high
concentration of carbonate and
quartz minerals provide
favorable conditions for fracture
development at Wolfcamp level
Fossil fragments
Quartz,
carbonate, and
fossils
Average Wolfcamp Shale components based on petrophysical analyses
and core data from AREX Baker A 112
W
E
4,000’
5,000’
6,000’
7,000’
8,000’
9,000’
10,000’
Depth
(feet)
Carbonate
26.2%
Quartz etc
36.8%
Porosity
7.0%
Clay
25.8%
TOC
4.2%
likely high fracture density areas
Wolfcamp
Faults

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APPROACH RESOURCES
Clearfork A
Clearfork B
Clearfork C
Hydrocarbon
bearing
zone
Wolffork
Hydrocarbon
Column
–
Over
2,500’
Thick
AREX Baker A 112
Wolfcamp
A
Wolfcamp
B
Wolfcamp
C
Hydrocarbon
bearing
zone
Current Lateral
Placement
Current Lateral
Placement

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APPROACH RESOURCES
Wolfcamp Regional Correlation
University 40-13 1H
Baker A 112
Bailey 310
~12.5 miles
~12.8 miles
SW Irion Co
Cinco Terry
Ozona NE

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APPROACH RESOURCES
*Density porosity ranges from 8% to 15%.
Notes: The shale rock property (SRP) data for Bakken, Barnett, Eagle Ford and Niobrara are from industry publications. The SRP data for Wolffork are based on AREX Baker A 112
whole core.
SHALE
Wolffork
Bakken
Barnett Oil
Combo
Eagle Ford
Niobrara
BASIN
Midland
Williston
Fort Worth
South Texas
DJ Basin
AGE
Permian
Late Devonian / early
Mississipian
Mississippian
Cretaceous
Cretaceous
DEPTH (feet)
4,000-8,000
7,000-11,000
6,500-8,500
8,000-12,000
7,000-9,000
THICKNESS (feet)
2,500-3,000
20-140
150-1,500
150-350
270-375
TOC (%)
2.2-7.2
2.0-18.0
4.5
2.0-6.5
4.0-4.5
TOTAL POROSITY (%)
4-11*
3-12
4-5
4-15
10-18
OOIP (MMboe)/640 Acres
119-182
5-10
100-200
27-57
20-30
Oil Shale Play Comparison
•
How
does
the
Wolffork
play
stack
up
against
other
commercial
oil
shale
plays?

APPROACH RESOURCES
Wolffork Oil Shale
Resource Play
PILOT PROGRAM, EVALUATION & FUTURE POTENTIAL

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APPROACH RESOURCES
AREX Wolffork Oil Shale Resource Play
•
Large, primarily contiguous acreage position
160,600 gross (142,000 net) acres
(~76% NRI)
Low acreage cost ~$350 per acre
•
Low-risk, long-life reserve base
64.8 MMBoe proved reserves
8.4 MMBoe proved reserves booked to
Wolffork oil shale resource play
57% liquids (51% proved developed)
Note: other large independents with Wolffork / Wolfberry
activities nearby include PXD, DVN and CXO
•
3 operated drilling rigs
2 vertical rigs, 1 horizontal rig
•
Vertical pilot program shifting to development
stage
152 BOEPD average IP for 9 recent Wolffork
recompletions (75% liquids)
140 BOEPD average IP for 7 recent vertical
Wolffork wells (72% liquids)

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APPROACH RESOURCES
AREX Wolffork Oil Shale Resource Play –
Activity Map
Crockett
Irion
Reagan
Schleicher
•
59,000 gross acres
•
Continue pilot program
•
Encouraging results from pilot wells
•
85,000 gross acres
•
Begin vertical development
•
Establish horizontal development
•
18,000 gross acres
•
3-D seismic acquisition completed
•
Begin horizontal drilling 1Q 2012
BAKER C 1201
CT B 1601
CT G 701H
CT M 901H
54-13 1
45 D 901H
42-21 1H
45 E 1101H
45 B 2401H
45 A 701H
Baker B 203
45 D 902H
Chandler 4403
CT B 1303
Childress 603
Childress G 1008
42 B 1001H
45 C 803H ST
54-12 1
54-15 1
42-11 2R
42-23 9
Vertical Pilot –
2    phase
Horizontal Pilot
Horizontal Drilling in Progress
Legend
Horizontal Waiting on Completion
54-9 1
54-19 3
54-2 1
54-15 2
54-16 3
CT B 1308
Baker A 114
West 2308
42-23 11
42-14 10
45 F 2301H
45 F 2302H
45 A 702H
Horizontal Permitted Location
3-D seismic
early-1Q 2012
nd
Pangea West
Pangea West
Northern & Central Pangea
Northern & Central Pangea
Southern Pangea
Southern Pangea

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APPROACH RESOURCES
AREX’s Wolffork Drilling Targets & Resource Potential
Notes: Potential locations based on 20-acre spacing for Vertical Wolffork, 20 to 40-acre spacing for Vertical Wolffork Recompletions, 40-acre spacing for Vertical Canyon Wolffork,
and 1,000-foot spacing between each horizontal well for Horizontal Wolfcamp.
PLAY TYPE
Vertical Wolffork
Vertical Wolffork
Recompletion
Vertical Canyon Wolffork
Horizontal
Wolfcamp
EUR (MBoe)
110
93
193
450
24-hr. IP (Boe/d)
80
72
170
325
Well cost ($ MM)
$1.2
$0.75
$1.5
$5.5
F&D ($ MM)
$10.91
$8.06
$7.77
$12.22
Potential locations
1,825
190
440
500
GROSS RESOURCE POTENTIAL
(MMBoe)
200+
17+
85
225
Target
Clearfork, Wolfcamp
Clearfork, Wolfcamp
Canyon, Clearfork, Wolfcamp
Wolfcamp
Drilling depth (ft.)
< 7,500
< 7,500
< 8,500
7,000+ (lateral length)
Activity (# of rigs)
1
2 -
4 recompl. / month
1
1
500+ MMBoe Total Gross Resource Potential

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APPROACH RESOURCES
Vertical Wolffork Well Profile
Annual
Decline
62%
29%
20%
15%
12%
10%
9%
8%
7%
6%
0
10
20
30
40
50
60
70
80
0
1
2
3
4
5
6
7
8
9
10
Year
Gross Oil (bbl/d)
Sales Gas (mcf/d)
Gross NGL (bbl/d)
BOE (bbl/d)
IP Profile
Avg. EUR
58 BO, 11 Bbls NGLs, 64 Mcf gas
110 MBoe

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APPROACH RESOURCES
Vertical Canyon Wolffork Well Profile
Annual
Decline
68%
32%
21%
16%
12%
10%
9%
8%
7%
6%
0
50
100
150
200
250
300
0
1
2
3
4
5
6
7
8
9
10
Year
Gross Oil (bbl/d)
Sales Gas (mcf/d)
Gross NGL (bbl/d)
BOE (bbl/d)
IP Profile
66 BO, 52 Bbls NGLs, 315 Mcf gas
Avg. EUR
193 MBoe

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APPROACH RESOURCES
Horizontal Wolfcamp Well Profile
Annual
Decline
62%
31%
21%
16%
13%
11%
9%
8%
7%
6%
IP Profile
230 BO, 47 Bbls NGLs, 285 Mcf gas
Avg. EUR
450 MBoe
0
50
100
150
200
250
300
350
Year
Gross Oil (bbl/d)
Sales Gas (mcf/d)
Gross NGL (bbl/d)
BOE (bbl/d)
0
1
2
3
4
5
6
7
8
9
10

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APPROACH RESOURCES
Horizontal Wolfcamp Well Performance
RECENT HORIZONTAL WOLFCAMP RESULTS
University 45 C 803H –
7,358’
lateral, 23 frac stages
University 45 B 2401H –
7,613’
lateral, 23 frac stages
University 45 D 902H –
7,770’
lateral, 23 frac stages
UPCOMING HORIZONTAL WOLFCAMP WELLS
University 42 B 1001H –
7,769’
lateral
Targeting the Wolfcamp “C”
zone
University 45 E 1101H –
7,712’
lateral
University 45 F 2301H –
7,749’
lateral
University 45 F 2302H –
7,698’
lateral
CONSISTENTLY IMPROVING  WELL RESULTS
200
400
600
800
1,000
1,200
CT M 901H
University 42
CT G 701H
University 45
University 45
University 45
natural gas
ngls
oil
Early 2011
9/2011
21 1H
A 701H
D 902H
B 2401H
C 803H
University 45
Initial 24-hour flow rate 1,044 BOEPD, 95%
liquids (931 BO, 57 Bbls NGLs, 335 MCFG)
Initial 24-hour flow rate 811 BOEPD, 86% liquids (582
BO, 116 Bbls NGLs, 677 MCFG)
Initial 24-hour flow rate 798 BOEPD, 88% liquids (611
BO, 95 Bbls NGLs, 552 MCFG)
-

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APPROACH RESOURCES
Key Investor Highlights
•
Concentrated geographic footprint focused on West Texas Midland Basin oil/liquids-rich play
142,000+ net, primarily contiguous acres, 100% operated
More than 575 wells drilled since 2004, with a 93%+ success rate
•
Strong growth track record at competitive costs
Reserve and production CAGR since 2007 of 26% and 21%, respectively
Low-cost operator with best-in-class F&D and lifting costs
•
Significant growth potential from Wolfcamp / Wolffork oil shale drilling inventory
2,900+ potential drilling and recompletion locations
Gross, unrisked resource potential totals more than 500+ MMBoe
•
Meaningful upside catalysts in near future
Wolffork oil shale resource play transitioning into development stage by Approach and other operators
Pioneer, El Paso and EOG allocating more capital to the play
Strong flow of new well result data should further derisk the play
•
Strong balance sheet to execute development plan
$260 MM borrowing base
$260 MM pro forma liquidity at 9/30/2011
Note: See liquidity calculation in appendix.

APPROACH RESOURCES
Financial Framework &
Non-GAAP Reconciliations

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APPROACH RESOURCES
Pre-Tax IRR Sensitivities of AREX’s Wolffork Drilling Targets
VERTICAL WOLFFORK
VERTICAL WOLFFORK RECOMPLETIONS
VERTICAL CANYON WOLFFORK
HORIZONTAL WOLFCAMP
0
20
40
60
80
100
105
110
115
120
Well EUR (MBoe)
$100 / bbl
$90 / bbl
$80 / bbl
$70 / bbl
0
20
40
60
80
180
185
190
195
200
Well EUR (MBoe)
$100 / bbl
$90 / bbl
$80 / bbl
$70 / bbl
0
20
40
60
80
350
400
450
500
550
Well EUR (MBoe)
$100 / bbl
$90 / bbl
$80 / bbl
$70 / bbl
0
20
40
60
80
76
85
93
102
110
Well EUR (MBoe)
$100 / bbl
$90 / bbl
$80 / bbl
$70 / bbl

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APPROACH RESOURCES
2012 Capital Budget
2012 PROGRAM
2012 Capital budget $160 MM
2 Vertical rigs, 1 horizontal rig and 2 to 4 recompletions per month targeting the Wolffork oil shale
Substantially same rig program as 2011
Targeting 20%+ production growth
2012
production
guidance
2,800
MBoe
–
3,000
MBoe
Key takeaways:
Initial 2012 capital program provides flexibility to develop Wolffork oil shale and monitor        
commodity prices and service costs
Increase in liquids production drives expected increase in cash flow
Increase in borrowing base strengthens liquidity
Notes: Our 2012 capital budget is subject to change depending upon a number of factors, including economic and industry conditions at the time of drilling, prevailing and
anticipated prices for oil, NGLs and natural gas, the availability sufficient capital resources for drilling prospects, our financial results, the availability of drilling and completion
services
and
materials
on
reasonable
terms,
and
lease
extensions
and
renewals.
Additionally,
we
may
increase
our
2012
capital
budget
if
we
acquire
acreage
or
accelerate
our
drilling program.

2012 Operating and Financial Guidance
Guidance is forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond the Company’s control.  See  slide 2, “Forward-looking
statements,”
for additional information.
2012
Guidance
Production
Total (MBoe)
2,800-
3,000
Percent Oil & NGLs
65%
Operating costs and expenses ($/per Boe)
Lease operating
$
$
$
$
$
4.50 –
5.50
Severance and production taxes
2.50 –
4.00
Exploration
4.00 –
5.00
General and administrative
5.25 –
6.25
Depletion, depreciation and amortization
12.00 –
15.00
Capital expenditures ($MM)
Approximately $160
| 26 |

| 27 |
APPROACH RESOURCES
•
Oil (NYMEX –
West Texas Intermediate)
–
2012
Collars
contracted
for
1,200
Bbls/d
at
weighted
average
floor
$87.08
–
ceiling
$101.08
–
2013 Collars  contracted for 650 Bbls/d
–
Floor $90.00 –
Ceiling $105.80
Hedge Position
CURRENT HEDGE POSITION

| 28 |
APPROACH RESOURCES
Liquidity (unaudited)
Note:  Liquidity as further adjusted is based on issuance of 4,600,000 shares at $28.00 per share.
(in thousands)
Liquidity at
September 30, 2011
Liquidity with Borrowing
Base increase at
September 30, 2011
Liquidity as further
adjusted for follow-on
equity offering at
September 30, 2011
Borrowing base
$
200,000
$
260,000
$
260,000
Cash and cash equivalents
736
736
736
Outstanding letters of
credit
(350)
(350)
(350)
Long-term debt
(122,000)
(122,000)
—
Liquidity
$
78,386
$
138,386
$
260,386
Liquidity is calculated by adding the net funds available under our revolving credit facility and cash and cash equivalents.  We use liquidity as an indicator of the Company’s ability
to fund development and exploration activities.  However, this measurement has limitations. This measurement can vary from year to year for the Company and can vary among
companies based on what is or is not included in the measurement on a company’s financial statements. This measurement 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 table below summarizes our liquidity at September 30, 2011, and our liquidity position at September 30, 2011, reflecting the October 2011 borrowing base increase to $260
million from $200 million, and our liquidity at September 30, 2011, as further adjusted for our November 2011 follow-on equity offering of 4,600,000 shares. 

| 29 |
APPROACH RESOURCES
We believe that providing measures of finding and development, or
F&D,
cost
is
useful
to
assist
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  SEC
filings and posted on our website. 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 we use 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 tables reflect the reconciliation of our estimated
finding and development costs to the information required by
paragraphs 11 and 21 of ASC 932-235.
F&D Costs Reconciliation (unaudited)
Note: F&D costs exclude asset retirement obligations of $6.3 million at 6/30/2011 and $5.4 million at 12/31/2010.
1H 2011 Reserve summary (Mboe)
Balance –
12/31/2010
Extensions  & discoveries
Purchases
Revisions
Production
50,715
8,910
10,497
(2,197)
(1,077)
66,848
Cost summary ($M)
Acquisitions
Exploration  costs
Development  costs
Total
85,714
$
4,914
72,061
162,689
Finding & development costs ($/Boe)
All-in F&D costs
Drill-bit F&D cost
9.45
8.64
$
$
Reserve replacement ratio (%)
Net reserve adds (Mboe)
1H’11 Production (Mboe)
Reserve replacement
17,210
(1,077)
1,598%
3-Year reserve summary (Mboe)
Balance –
12/31/2007
Balance –
12/31/2010
Extensions  & discoveries
Purchases
Revisions
Production
30,067
15,880
3,244
6,008
(4,484)
50,715
Cost summary ($M)
Acquisitions
Exploration  costs
Development  costs
Total
Finding & development costs ($/Boe)
3-year All-in F&D  costs
3-year Drill-bit F&D  cost
8.78
11.96
Reserve replacement ratio (%)
Net reserve adds  (Mboe)
3-year Production  (Mboe)
Reserve  replacement
25,132
(4,484)
561%
$
$
Balance –
6/30/2011
30,605
9,364
180,568
220,537
$

| 30 |
APPROACH RESOURCES
We define EBITDAX as net income, plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4)
unrealized (gain) loss on commodity derivatives, (5) gain on sale of oil and gas properties, (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 our website.
EBITDAX Reconciliation (unaudited)
(in thousands, except per-share amounts)
Three Months Ended
September 30,
2011
2010
Net income
$
7,073
$
2,087
Exploration
1,969
568
Depletion, depreciation and amortization
8,355
5,832
Share-based compensation
1,089
1,047
Unrealized (gain) loss on commodity derivatives
(1,739)
312
Interest expense, net
1,016
615
Income tax provision
3,908
1,167
EBITDAX
$
21,671
$
11,628
EBITDAX per diluted share
$
0.76
$
0.54

APPROACH RESOURCES
Contact Information
MEGAN P. HAYS
MANAGER, IR & CORPORATE COMMUNICATIONS
817.989.9000 X 2108
MHAYS@APPROACHRESOURCES.COM

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