EX-99.2 3 d521436dex992.htm EX-99.2 EX-99.2
Approach Resources Inc.
IPAA’S OIL & GAS INVESTMENT SYMPOSIUM
NEW YORK
APRIL 15, 2013
Exhibit 99.2

2

Company Overview
•
Enterprise value $1.1 BN
•
High quality reserve base
95.5 MMBoe proved reserves
99% Permian Basin
•
Permian core operating area
•
2013 Capital program of $260 MM
3
AREX OVERVIEW
ASSET OVERVIEW
Notes:
Proved
reserves
and
acreage
as
of
12/31/2012.
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 $24.75 per share on 4/8/2013, plus net debt as of 12/31/2012.
167,000 gross (148,000 net) acres
1+ BnBoe gross, unrisked resource
potential
2,000+ Identified HZ drilling locations
targeting the Wolfcamp oil shale play
Running 3 HZ rigs in the Wolfcamp shale
play
Targeting 30%+ production growth

Reserve Growth
4
RESERVE GROWTH
OIL RESERVE GROWTH
•
YE’12 reserves up 24% YoY
•
Replaced 1,346% of reserves at a drill-bit F&D
cost of $7.45/Boe
•
60.1 MMBoe proved reserves booked to
Wolffork/Wolfcamp 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
Notes: See “F&D Costs Reconciliation”
slide in appendix.

Production Growth
5
PRODUCTION GROWTH
OIL PRODUCTION GROWTH
3.6 MMBoe –
3.9 MMBoe in 2013
2013E Production mix ~70% liquids
•
Strong organic production growth driven by
oil from horizontal Wolfcamp shale
•
Oil production up 3x
since 2009
•
Oil production up 101%
over 2011
•
2012 production increased 24% YoY
•
Targeting 30%+ production growth in 2013

Low-Cost Operator
Notes:
Peers
include
CXO,
FANG,
KOG,
LPI,
OAS,
PXD,
ROSE
and
SM.
Data
based
on
SEC
filings
for
twelve
months
ending
December
31,
2012.
3-YR AVERAGE F&D COSTS ($/Boe)
LEASE OPERATING EXPENSE ($/Boe)
6

AREX Wolfcamp Oil Shale Resource Play
7
ACTIVE PARTICIPANTS IN THE PLAY
Large, primarily contiguous acreage position
Oil-rich, multiple pay zones
167,000 gross (148,000 net) acres
Low acreage cost ~$500 per acre
940+ MMBoe gross, unrisked resource potential
2,096 Identified HZ Wolfcamp locations targeting
the Wolfcamp A, B & C
Plan to drill ~ 35 to 40 HZ wells with 3 rigs
Testing “stacked-wellbore”
development and
tighter well spacing
Decrease well costs and increase efficiencies
when field infrastructure projects are completed
Source: Rig data from Schlumberger and Iberia.
HZ Wolfcamp resource potential up 300%+
2013 Operations
Broad industry participation de-risking play
50+ HZ Wolfcamp rigs as of April 2013

AREX Drilling Locations, Targets & Resource Potential
8
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
(MBoe)
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

Wolfcamp Oil Shale Play
9
WOLFCAMP SHALE –
WIDESPREAD, THICK, CONSISTENT & REPEATABLE

Horizontal Wolfcamp –
82% of IP is Oil
10
Sutton
Source: Publicly available regulatory filings, company presentations.

Misconception vs. Facts
11
Misconception: Wells are
gassier as the play moves
southward
•
Gassier wells are historical
Canyon, Strawn and
Ellenburger wells
•
The Wolfcamp Shale is located
in peak oil and early wet gas
window. Wolfcamp wells are
expected to produce
approximately 58% oil and
~80% liquids over the
production life, supported by
core data, initial production data
and EUR forecast

AREX HZ Wolfcamp Activity
12
Notes: Acreage as of 12/31/2012.
Pangea West
North & Central Pangea
South Pangea
•
18,000 gross acres
•
Pad drilling with A/B and A/C “stacked”
laterals
Schleicher
Crockett
Irion
Reagan
•
3-D seismic interpretation
completed
•
Drilling HZ pilot well
•
59,000 gross acres
•
Continuing completion
design improvement
•
90,000 gross acres
•
Pad drilling with A/B and A/C “stacked”
laterals
•
North Pangea infrastructure in place in 2Q’13
Sutton
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 905H
45 A 704H
CT K 1901
CT K 1902
45 D 904H
45 E 1102H
Baker B 207H
Baker B 206H
CT H 1004H
U 50 A 601HC
PW 6533H
PW 6535H
45 F 2304H
45 A 706H
45A 708H
45A 710H
45A 712H
Elliott 2002HB
CT M 902
•
3-D Seismic acquisition completed.
Data processing in progress
•
Targeting HZ pilot well in 2Q’13
U 50 A 603HA

HZ Wolfcamp Well Performance
13
Time (Days)
CONTINUED STRONG WELLS RESULTS –
TRACKING ABOVE THE TYPE CURVE

Microseismic Data –
Wolfcamp A & B
15
MAP VIEW
X-SECTION VIEW (LOOKING WEST)

16
Microseismic Data –
Wolfcamp C
MAP VIEW
X-SECTION VIEW (LOOKING WEST)

17
Multiple Lateral Stacking –
Effective Frac Volumes
CHEVRON STACKING DEVELOPMENT PATTERN

AREX HZ Wolfcamp Economics
18
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
(58% OIL)
•
3 HZ rigs running in Project Pangea /
Pangea West

Infrastructure for Large-Scale  Development
19
•
Reducing D&C Cost to $5.5 MM or lower
•
Reducing LOE
•
Minimizing truck traffic and surface
disturbance
•
Increasing project profit margin
Pangea
West
South
Pangea
Schleicher
Crockett
Irion
Reagan
Sutton
North & Central
Pangea

Infrastructure & Equipment Projects
20
•
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
21
Hitting $5.5 MM HZ well cost target in 2Q’13
Testing multi-bench “stacked”
laterals and tighter well
spacing
Transition to full-field development

Financial Information
NON-GAAP RECONCILIATIONS

2013 Capital Budget
•
2013 Capital budget $260 MM, approx. 90% for HZ Wolfcamp
•
3 HZ rigs in the Wolfcamp shale
•
Targeting 30%+ production growth
Key takeaways:
23
•
Targeting Wolfcamp A, B and C
•
Testing “stacked”
lateral development concept
•
2013 Production guidance 3.6 MMBoe –
3.9 MMBoe
•
2013E Production mix 70% liquids
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
$280 MM borrowing base strengthens liquidity

2013 Operating and Financial Guidance
24
2013 GUIDANCE
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

Hedge Position
25
CURRENT HEDGE POSITION
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
February 2013 –
December 2013
Collar
1,200 Bbls/d
$90.35/Bbl -
$100.35/Bbl
2014
Collar
550 Bbls/d
$90.00/Bbl -
$105.50/Bbl
Crude Oil Basis Differential (Midland/Cushing)
March 2013 –
December 2013
Swap
2,300 Bbls/d
$1.10/Bbl
Natural Gas
2013
Swap
200,000 MMBtu/month
$3.54/MMBtu
2013
Swap
190,000 MMBtu/month
$3.80/MMBtu
May 2013 –
December 2013
Collar
100,000 MMBtu/month
$4.00/MMBtu -
$4.36/MMBtu
2014
Swap
360,000 MMBtu/month
$4.18/MMBtu
53% of FY’13 oil hedged at $90.17/Bbl x $102.19/Bbl
81% of FY’13 gas hedged at weighted average floor of $3.72/MMBtu
•
Prudent hedging program protects cash flow and returns as well as capital budget activities

Conservative Financial Strategy & Capitalization
26
CAPITALIZATION &
PERFORMANCE
METRICS
(1) Liquidity calculated as the sum of current borrowing base and cash and cash equivalents less long-term debt and unused letters of credit. Unused
letters of credit currently total $325,000.

EBITDAX (unaudited)
27
We
define
EBITDAX
as
net
income,
plus
(1)
exploration
expense,
(2)
impairment
expense,
(3)
depletion,
depreciation
and
amortization
expense,
(4)
share-
based
compensation
expense,
(5)
unrealized
(gain)
loss
on
commodity
derivatives,
(6)
gain
on
sale
of
oil
and
gas
properties,
(7)
interest
expense
and
(8)
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
and
year
ended
December
31,
2012
and
2011,
respectively
(in
thousands,
except
per-share
amounts).
(in thousands, except per-share amounts)
Year Ended
December 31,
2012
2011
Net income
$
6,384
$
7,242
Exploration
4,550
9,546
Impairment
—
18,476
Depletion, depreciation and amortization
60,381
32,475
Share-based compensation
7,465
4,683
Unrealized (gain) loss on commodity derivatives
(3,874)
347
Gain on sale of oil & gas properties
—
(248)
Interest expense, net
4,737
3,402
Income tax provision
3,338
3,488
EBITDAX
$
82,981
$
79,411
EBITDAX per diluted share
$
2.37
$
2.72

F&D Costs Reconciliation (unaudited)
28
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.
2012 Reserve summary (MBoe)
Balance –
12/31/2011
76,975
Extensions  & discoveries
38,861
Revisions
(17,469)
Production
(2,888)
Balance –
12/31/2012
95,479
Cost summary ($M)
Acquisition costs
$
7,742
Exploration costs
4,550
Development costs
285,039
Total
297,331
Finding & development costs ($/Boe)
All-in F&D costs
$
13.90
Drill-bit F&D cost
$
7.45
Reserve replacement ratio (%)
Extensions & discoveries (MBoe)
38,861
2012 Production (MBoe)
(2,888)
Reserve replacement
1,346%
3-Year Reserve summary (MBoe)
Balance –
12/31/2009
36,488
Extensions  & discoveries
68,182
Purchases
12,456
Revisions
(14,866)
Production
(6,781)
Balance –
12/31/2012
95,479
Cost summary ($M)
Acquisition costs
$
131,189
Exploration costs
17,415
Development costs
524,476
Total
673,080
Finding & development costs ($/Boe)
3-YR All-in F&D costs
$
10.23
3-YR Drill-bit F&D cost
$
7.95
Reserve replacement ratio (%)
Extensions & discoveries (MBoe)
68,182
3-YR Production (MBoe)
(6,781)
Reserve replacement
1,005%

Contact
Information
MEGAN P. HAYS
Manager, Investor Relations & Corporate Communications
817.989.9000 x2108
mhays@approachresources.com
www.approachresources.com