Attached files
| file | filename |
|---|---|
| 8-K - 8-K - Approach Resources Inc | d578449d8k.htm |
| EX-99.1 - EX-99.1 - Approach Resources Inc | d578449dex991.htm |
 Approach Resources Inc.
SECOND QUARTER 2013 RESULTS
AUGUST 1, 2013
EXHIBIT 99.2 |
 Forward-Looking Statements
2
Cautionary Statements Regarding Oil & Gas Quantities
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. 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.
|
 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
$25.99
per
share
on
7/29/2013,
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
•
Substantial liquidity of $370 MM as of 6/30/2013
•
Active hedging program
•
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. |
 Strong Track Record of Reserve Growth…
5
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
0
20
40
60
80
100
120
2004
2005
2006
2007
2008
2009
2010
2011
2012
Natural Gas (MMBoe)
Oil & NGLs (MMbbls)
0
5
10
15
20
25
30
35
40
2009
2010
2011
2012
Oil (MMBbls) |
 …and Production Growth
6
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
0
200
400
600
800
1000
1200
2009
2010
2011
2012
Oil (MBbls)
Natural Gas (MBoe/d)
Oil & NGLs (Mbbls/d)
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0
9.0
2004
2005
2006
2007
2008
2009
2010
2011
2012 |
 2Q13 Operating & Financial Highlights
7
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
|
 Oil & Liquids-Weighted Reserves, Production & Revenue
8
YE12 RESERVE MIX BY COMMODITY
2Q13 PRODUCTION MIX BY COMMODITY
2Q13 REVENUE MIX BY COMMODITY
95.5
MMBoe
$42.3
MM
9.0
MBoe/d
31%
30%
39%
30%
42%
28%
13%
15%
72%
Oil
NGLs
Gas
Oil
NGLs
Gas
Oil
NGLs
Gas |
 AREX Wolfcamp Oil Shale Resource Play
9
Plan to drill ~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
2,096 Identified HZ Wolfcamp locations targeting
the Wolfcamp A, B & C
940+ MMBoe gross, unrisked HZ Wolfcamp
resource potential |
 Wolfcamp Oil Shale Play
10
WOLFCAMP SHALE –
WIDESPREAD, THICK, CONSISTENT & REPEATABLE |
 Wolfcamp Stacked Pay Zones
HZ TARGETS & RESOURCE POTENTIAL
HZ WOLFCAMP
TARGET
Wolfcamp
A
Wolfcamp
B
Wolfcamp
C
Identified locations
703
690
703
EUR (MBoe)
450
450
450
Gross Reference
Potential (MMBoe)
316
310
316
940+ MMBoe Total Gross
Resource Potential
Notes: Identified locations based on multi-bench development and 120-acre
spacing. No locations assigned to south Project Pangea. 11
Wolfcamp A
Wolfcamp B
Wolfcamp C
Wolfcamp
Top
AREX Baker A 112
5500
5600
5700
5800
5900
6000
6100
6200
6300
6400
6500
0
200
GR API
0.2
2,000
0.3
-0.1
0.2
0
20
200
MSFL OHMM
0.2
2,000
LLD OHMM
NPHI
0.3
-0.1
DPHI
Free Hydrocarbon
0.2
0
BVW
20
200 |
 AREX HZ Wolfcamp Activity
12
Notes: Acreage as of 6/30/2013.
Schleicher
Crockett
Irion
Reagan
Sutton
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)
Legend |
 HZ
Wolfcamp Well Performance 13
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
Daily Production Data from
AREX A Bench Wells
450 MBoe Type Curve
Wolfcamp Oil Shale
Daily Production Data from
AREX B Bench Wells
B Bench Well Data (27 wells)
A Bench Well Data (3 wells)
450 MBoe Type Curve
Legend
CONTINUED STRONG WELL RESULTS & MORE PRODUCTION HISTORY –
TRACKING
ABOVE THE TYPE CURVE |
 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.
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
•
3 HZ rigs running in Project Pangea / Pangea
West
Well EUR (MBoe)
0
10
20
30
40
50
60
70
80
350
400
450
500
550
$100 / bbl
$90 / bbl
$80 / bbl
$70 / bbl |
 AREX Drilling Locations, Targets & Resource Potential
15
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
16
•
Reducing D&C Cost to $5.5 MM or 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 |
 Infrastructure & Equipment Projects
17
•
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
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
•
Efficiently transport crude oil to market and reduce inventory
•
Reduce
oil
transportation
differential
to
an
estimated
$2.50/Bbl
–
$4.00/Bbl |
 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
18
Hitting $5.5 MM HZ well cost target
Testing multi-bench “stacked”
laterals and closer well spacing
Transition to full-field development |
 Financial
Information
NON-GAAP RECONCILIATIONS |
 2013 Capital Budget
20
•
2013 Capital budget $260 MM, approx. 90% for HZ Wolfcamp
•
Targeting Wolfcamp A, B and C
•
Testing
“stacked-wellbore”
development
•
Optimizing well spacing and completion design
•
Targeting 25%+ production growth
•
2013
Production
guidance
3.6
MMBoe
–
3.9
MMBoe
•
2013E Production mix 70% liquids
Key takeaways:
2013 capital program provides flexibility to develop Wolfcamp oil shale and
monitor commodity prices and service costs
Increase in oil production drives expected increase in cash flow
Senior notes issuance and undrawn borrowing base strengthen liquidity
•
3 HZ rigs in the Wolfcamp shale |
 Strong, Simple Balance Sheet
21
FINANCIAL RESULTS ($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
$2.04
Notes:
Estimated
proved
reserves
as
of
12/31/2012.
EBITDAX
is
a
non-GAAP
financial
measure.
See
“EBITDAX”
slide
and
website
for
reconciliation.
Net debt is debt balance less available cash and letters of credit.
Strong Balance Sheet and Liquidity to Develop
HZ Wolfcamp Shale |
 2013 Operating and Financial Guidance
22
Full-Year 2013
Guidance
Production
Total (MBoe)
3,600 –
3,900
Percent Oil & NGLs
70%
Operating costs and expenses ($/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. |
 Current Hedge Position
23
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
2013 (1)
Collar
1,200 Bbls/d
$90.35/Bbl -
$100.35/Bbl
2014
Collar
550 Bbls/d
$90.00/Bbl -
$105.50/Bbl
2014
Collar
650 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)
2013 (2)
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
2013 (3)
Collar
100,000 MMBtu/month
$4.00/MMBtu -
$4.36/MMBtu
2014
Swap
360,000 MMBtu/month
$4.18/MMBtu
(1)
February
2013
–
December
2013
(2)
March
2013
–
December
2013
(3)
May
2013
–
December
2013 |
 Adjusted Net Income (unaudited)
24
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 |
 25
(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
EBITDAX (unaudited)
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. |
 Contact
Information
MEGAN P. HAYS
Manager, Investor Relations & Corporate Communications
817.989.9000 x2108
mhays@approachresources.com
www.approachresources.com |