 INVESTOR
PRESENTATION
OCTOBER 2012
Exhibit 99.1 |
 Forward Looking-Statements
2
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 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, potential 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. |
 Notes: Proved reserves and acreage as of 6/30/2012. 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
$30.06
per
share
on
9/27/2012,
plus
estimated
net
debt
as
of
9/30/2012.
Company Overview
•
Enterprise value $1.2 BN
•
High quality reserve base
•
Permian core operating area
166,000 gross (146,000 net) acres
500+ MMBoe gross, unrisked resource
potential
2,900+ drilling and recompletion opportunities
•
Oil-driven growth in Q2 2012
Q2’12 Production 7.7 MBoe/d, 65% oil & NGLs
Q2’12 Revenue mix 64% oil, 25% NGLs and
11% natural gas
3
AREX OVERVIEW
ASSET OVERVIEW
83.7
MMBoe
proved
reserves,
37%
PD
99%
Permian
Basin |
 Oil-Focused,
Pure-Play
•
Transitioning Wolfcamp B to development mode and preparing for full-scale
exploitation •
Pilot program evaluating additional Wolfcamp zones (A and C benches)
•
Adding
3
rd
horizontal
rig
in
January
2013
•
Concentrated geographic footprint in the southern Midland Basin
•
146,000 net, primarily contiguous acres, 100% operated
•
64% of proved reserves are oil and NGLs
Track Record of
Growth at Low
Costs
Accelerating
Horizontal
Wolfcamp
Development
•
Reserve and production CAGR since 2004 of 33% and 37%, respectively
•
Low-cost operator with best-in-class F&D and low lifting
costs •
$270 MM borrowing base
•
$222.6 MM estimated liquidity at 9/30/12
Strong Balance
Sheet
Multi-Year
Drilling Inventory
and Significant
Resource
Potential
•
2,900+ identified drilling and recompletion locations
•
500+ MMBoe of gross, unrisked resource potential
•
Rigorous pilot program has de-risked ~100,000 gross acres
•
Additional upside potential from tighter well spacing and multi-zone
development Key Investor Highlights
4
STRENGTHS
HIGHLIGHTS
Note: See liquidity calculation in appendix. |
 Track
Record of Reserve and Production Growth •
MY’12 reserves up 25% YoY and 9% over YE’11
Oil reserves up 30% to 23.5 MMbbls
•
Wolfcamp Shale key contributor to reserve growth
5
RESERVE GROWTH
PRODUCTION GROWTH
•
2011 production increased 50% YoY
•
Targeting 28% production growth in 2012
•
Strong liquids production growth
2012E production 65% liquids
0
10
20
30
40
50
60
70
80
90
2004
2005
2006
2007
2008
2009
2010
2011
MY'12
Natural Gas (MMBoe)
Oil & NGLs (MMbbls)
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0
2004
2005
2006
2007
2008
2009
2010
2011
MY'12
Natural Gas (MBoe/d)
Oil & NGLs (Mbbls/d)
500+
MMBoe
gross,
unrisked
resource
potential |
 Low-Cost Operator
6
3-YR AVERAGE F&D COSTS ($/BOE)
2Q’12 LIFTING COSTS ($/BOE)
Notes: Oil weighted peers include BRY, CXO, KOG, LPI, NOG, OAS. Data based on SEC
filings and J.S. Herold data. 3-YR F&D costs represent drill-bit F&D
costs (drill-bit F&D costs defined as Exploration and Development Costs
divided by Reserve Extensions & Discoveries and Revisions less Production). See F&D
costs reconciliation in appendix. Lifting costs defined as lease operating
expense plus taxes other than income and gathering and transportation expense. |
 Extensive Inventory of Future Drilling Locations
7
POTENTIAL DRILLING LOCATIONS
Gross Resource
Potential (MMBoe):
225
200+
17+
85
500+
500+ MMBoe Total Gross Resource Potential |
 AREX
Wolfcamp Play Favorably Located in the S. Midland Basin 8
Wolfcamp / Wolffork Oil
Shale Resource Play |
 AREX
Wolfcamp Oil Shale Resource Play 9
ACTIVE PARTICIPANTS IN THE PLAY
Note: Number of Horizontal Wolfcamp rigs per PXD July 2012 investor
presentation. Average 24-hr. IP rate and average lateral well length based on public
disclosure from AREX, EOG, PXD.
Large, primarily contiguous acreage position
Liquids-rich, multiple pay zones 166,000 gross
(146,000 net) acres
Low acreage cost ~$500 per acre
500+ MMBoe gross, unrisked resource potential 2,900+ drilling
and recompletion opportunities Early-stage play development Transitioning
Wolfcamp B to development mode Testing Wolfcamp
A and C
Testing tighter well spacing Preparing field
for large-scale development Broad industry participation de-risking play 41 Horizontal
Wolfcamp rigs as of July 2012
Average 24-hr. IP rate of 807 Boe/d in 2Q’12 Average lateral
well length of ~7,100 ft.
|
 10
Wolfcamp Oil Shale Play –
Widespread, Thick, Consistent & Repeatable |
 Horizontal Wolfcamp Targets
11
SYSTEM
STRATIGRAPHIC
UNIT
Permian
Clearfork/Spraberry
Dean
Wolfcamp
Pennsylvanian
Canyon
Strawn
Mississippian
Devonian
Silurian
Ordovician
Ellenburger
WOLFCAMP A
WOLFCAMP B
WOLFCAMP C
WOLFCAMP D
Pilot
Transitioning
to
Development
Pilot
–
Recent
Results
Encouraging
Under
Evaluation
POTENTIAL HORIZONTAL
WOLFCAMP TARGETS |
 12
AREX
DVN
PXD
Highmount
EP
EOG
Average ~82% Oil
59 wells from AREX, DVN, EOG, EP, Highmount and PXD
Wolfcamp Horizontal Wells -
82% of IP is Oil
Source: Publicly available regulatory filings, company presentations.
|
 Wolfcamp Horizontal Wells -
95% of IP is Liquids
13
AREX
DVN
PXD
Highmount
EP
EOG
Average ~95% Liquids
59 wells from AREX, DVN, EOG, EP, Highmount and PXD
Source: Publicly available regulatory filings, company presentations.
|
 AREX
Recent Well Results 14
IP MIX –
LAST 10 HZ B WELLS
24 HR.-
IP –
LAST 10 HZ B WELLS
HZ WOLFCAMP WELL RESULTS
Boe/d
Average: 918 Boe/d
Average: 82% oil
72%
89%
87%
87%
92%
92%
65%
76%
76%
85%
0%
20%
40%
60%
80%
100%
Oil
NGLs
Gas
14%
6%
7%
7%
4%
5%
19%
13%
13%
8%
14%
5%
6%
6%
4%
3%
16%
11%
11%
7%
811
1,044
1,310
1,136
687
892
676
634
1,111
875
0
200
400
600
800
1,000
1,200
1,400
Note: IP’s based on 24-hr. rates. We also recently completed three HZ B wells with an
average IP of 500 Boe/d, made up of 62% oil and 83% total liquids. The average lateral
length of the three HZ wells was 6,360 feet, including one well that was a 3,078-feet lateral. As part of ongoing cost cutting efforts, we
reduced the amount of certain chemicals used in completing these wells. We believe that the
change in the chemical composition of the frac fluid negatively affected the IP of these wells,
and, accordingly, the results from these three HZ wells are not included in the above tables.
Completion
date
Well name
IP
(Boe/d)
Oil
(Bbl/d)
NGL
(Bbl/d)
Gas
(Mcfe/d)
IP %
Liquids
No. of
stages
B Bench:
May 2012
University 45 A #703H
875
743
73
354
93%
29
Mar 2012
University 45 F #2304H
1,111
840
150
729
89%
28
Mar 2012
University 45 F #2303H
634
481
84
412
89%
30
Feb 2012
University 45 C #805H
676
441
130
632
84%
28
Feb 2012
University 45 C #804H
892
823
38
185
97%
35
Dec 2011
University 45 E #1101H
687
632
30
147
96%
35
Dec 2011
University 45 F #2302H
1,136
986
83
404
94%
28
Dec 2011
University 45 F #2301H
1,310
1,136
96
467
94%
34
Sep 2011
University 45 C #803H
1,044
931
57
335
95%
23
Sep 2011
University 45 B #2401H
811
582
116
677
86%
23
Sep 2011
University 45 D #902H
798
611
95
552
88%
23
Jun 2011
University 45 A #701H
694
613
41
237
94%
21
May 2011
CT G #701H
328
168
81
473
76%
23
Apr 2011
University 42-21 #1H
316
132
93
543
71%
21
Mar 2011
CT M #901H
171
51
61
355
65%
15
A Bench:
Jun 2012
Pangea West #6601H
461
388
40
196
93%
29
Jun 2012
Pangea West #6602H
494
391
57
278
91%
28
C Bench:
Nov 2011
University 42 B #1001H
541
324
120
584
82%
28 |
 AREX
Wolfcamp Play – Activity Map
15
Pangea West
North & Central Pangea
South Pangea
•
18,000 gross acres
•
2 HZ pilot wells with encouraging results
Schleicher
Crockett
Irion
Reagan
•
Interpreting
newly
acquired
3D
seismic
•
Targeting
HZ
pilot
well
in
Q4’12
•
59,000 gross acres
•
Continuing completion
design improvement
•
89,000 gross acres
•
Continuing HZ and V development
•
Continuing refining completion designs
Sutton
Legend
Vertical Producer
HZ Producer
HZ –
Waiting on Completion
HZ –
Drilling
HZ –
Permit
Note: Acreage as of 6/30/2012.
•
3D Seismic acquisition underway
•
Targeting HZ pilot well in Q4’12 |
 Horizontal Wolfcamp Economics
16
Play Type
Horizontal
Wolfcamp
Avg. EUR
450 MBoe
Targeted Well Cost
$5.5 MM
Potential Locations
500
Gross Resource
Potential
225 MMBoe
BTAX IRR SENSITIVITIES
•
2 HZ rigs running in Pangea / Pangea West
•
Improving IPs and liquids ratio driving higher
returns
•
Recent well results range from 634 BOEPD to
1,310 BOEPD, made up of 84% to 97% liquids
•
875 BOEPD initial IP for Univ. 45 A 703H, made up of
85% oil and 93% total liquids
•
612 BOEPD and 539 BOEPD average 30-day and
60-day rates, respectively, for Univ. 45 A 703H
Notes: IP’s based on 24-hr. rates. Potential locations are based on
1,000-feet spacing between each horizontal well. Economics assume NYMEX gas strip and NGL
price based on 40% of WTI oil price.
•
Horizontal drilling improves recoveries and
returns
•
Multiple, stacked horizontal targets
•
7,000’+ lateral length
•
~80% of EUR made up of oil and NGLs
•
2 HZ rigs running in Project Pangea / Pangea
West
•
Adding 3 HZ rig in January 2013
0
10
40
50
60
70
80
350
400
450
500
550
Well EUR (MBoe)
$100 / bbl
$90 / bbl
$80 / bbl
$70 / bbl
20
30
rd |
 Horizontal Wolfcamp Type Curve
17
Month
100
1,000
10,000
100,000
6
12
18
24
30
36
42
48
54
60
0
Oil (barrels per month)
NGL (barrels per month)
Shrunk Gas (boe per month)
Oil 45-701H
NGL 45-701H
Shrunk Gas 45-701H
Total (boe per month)
Total 45-701H
450,000 Boe
Type Curve
Production data
(9 months)
University 45-701H
U 45-701H IP 694 Boe/d
Type Curve IP 589 Boe/d |
 Clearfork & Wolfcamp (“Wolffork”) Economics
18
BTAX IRR SENSITIVITIES
Notes: Vertical Wolffork potential locations based on 20-acre spacing.
Vertical Wolffork recompletion potential locations based on 20 to 40-acre spacing.
Economics assume NYMEX gas strip and NGL price based on 40% of WTI oil price.
Play
Type
Vertical Wolffork
Recompletion
Avg. EUR
93 MBoe
Targeted Well Cost
$0.75 MM
Potential Locations
190
Gross
Resource
Potential
17+
MMBoe
BTAX IRR SENSITIVITIES
0
10
20
30
40
100
105
110
115
120
Well EUR (MBoe)
$100 / bbl
$90 / bbl
$80 / bbl
$70 / bbl
0
10
20
30
40
50
60
70
80
76
86
96
106
Well EUR (MBoe)
$100 / bbl
$90 / bbl
$80 / bbl
$70 / bbl
Play
Type
Vertical
Wolffork
Avg. EUR
110 MBoe
Targeted Well Cost
$1.2 MM
Potential Locations
1,825
Gross
Resource
Potential
200+
MMBoe |
 AREX
Drilling Targets & Resource Potential 19
PLAY TYPE
Horizontal
Wolfcamp
Vertical
Wolffork
Vertical Wolffork
Recompletion
Vertical Canyon
Wolffork
EUR (MBoe)
450
110
93
193
Targeted well cost ($MM)
$5.5
$1.2
$0.75
$1.5
Potential locations
500
1,825
190
440
GROSS RESOURCE
POTENTIAL (MMBoe)
225
200+
17+
85
Target
Wolfcamp
Clearfork,
Wolfcamp
Clearfork, Wolfcamp
Canyon, Clearfork,
Wolfcamp
Drilling depth (ft.)
7,000+ (lateral
length)
< 7,500
< 7,500
< 8,500
500+ MMBoe Total Gross Resource Potential
Notes: Potential locations based on 1,000-feet spacing between each horizontal
well for Horizontal Wolfcamp, 20-acre spacing for Vertical Wolffork, 20 to 40-
acre spacing for Vertical Wolffork Recompletion and 40-acre spacing for Vertical
Canyon Wolffork. |
 Infrastructure & Equipment Projects
20
•
Safely and securely transport water across Project Pangea and Pangea West
and reduce truck traffic
•
Reduce time and money spent on water hauling and disposal
•
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
•
Reduce water costs
•
Efficiently transport crude oil to market and reduce inventory
•
Reduce oil differential
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
PROJECTS
BENEFITS
Infrastructure and equipment projects are key to large-scale field
development and to reducing D&C costs and
monthly LOE |
 2012
& 2013 Capital Programs 21
Infrastructure &
Equipment
Vertical Wolffork &
Recompletions
Horizontal
Wolfcamp
Acreage
•
Horizontal Wolfcamp
2 horizontal rigs
Beginning development program of B zone
Testing A & C zones
•
Vertical Clearfork & Wolfcamp
1 vertical rig and recompletion program
2012 PROGRAM OVERVIEW
2012 Capital Program $260 MM
•
Horizontal Wolfcamp
3 horizontal rigs to drill 35 to 40 wells
•
Vertical Clearfork & Wolfcamp
1 vertical rig to drill 12 wells
Recompletion program
2013 PROGRAM OVERVIEW
Vertical Wolffork &
Recompletions
Horizontal
Wolfcamp
Acreage,
Infrastructure
& Equipment
2013 Capital Program $260 MM
29%
14%
2%
55%
2%
10%
88% |
 Creating Value Through Growth
22
•
Concentrated geographic footprint in the Southern Midland Basin
•
Strong growth track record at competitive costs
•
Detailed technical evaluation led to discovery of significant growth
potential in the Wolfcamp / Wolffork oil shale resource play
•
Rigorous pilot program de-risked ~100,000 gross acres
•
Capital discipline for Wolfcamp / Wolffork program acceleration
|
 Financial
Framework
NON-GAAP RECONCILIATIONS |
 2012
Operating and Financial Guidance 24
2012 GUIDANCE
2012 Guidance
Production
Total (MBoe)
2,900 -
3,100
Percent Oil & NGLs
65%
Operating costs and expenses ($/per Boe)
Lease operating
$
5.50 –
6.50
Severance and production taxes
$
2.50 –
4.00
Exploration
$
4.00 –
5.00
General and administrative
$
7.00 –
8.00
Depletion, depreciation and amortization
$
15.00 –
18.00
Capital expenditures ($MM)
Approximately $260 |
 Hedge Position
25
CURRENT HEDGE POSITION
Commodity and Time Period
Type
Volume
Price
Crude Oil
2012
Collar
700 Bbls/d
$85.00/Bbl -
$97.50/Bbl
2012
Collar
500 Bbls/d
$90.00/Bbl -
$106.10/Bbl
September 2012 –
December 2012
Collar
350 Bbls/d
$90.00/Bbl -
$102.30/Bbl
2013
Collar
650 Bbls/d
$90.00/Bbl -
$105.80/Bbl
2013
Collar
450 Bbls/d
$90.00/Bbl -
$101.45/Bbl
2014
Collar
550 Bbls/d
$90.00/Bbl -
$105.50/Bbl
Natural Gas Liquids
Natural Gasoline –
February 2012 –
December 2012
Swap
225 Bbls/d
$95.55/Bbl
Normal Butane –
March 2012 –
December 2012
Swap
225 Bbls/d
$73.92/Bbl
Natural Gas
2012
Call
230,000 MMBtu/month
$6.00/MMBtu
July 2012 –
December 2012
Swap
360,000 MMBtu/month
$2.70/MMBtu
2013
Swap
200,000 MMBtu/month
$3.54/MMBtu |
 Financial Strength
26
Liquidity
(preliminary
and
unaudited)
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. Liquidity has limitations,
and 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. Liquidity 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 estimated liquidity at
September 30, 2012. Estimated liquidity includes net proceeds from our follow-on equity
offering of 5.0 million shares at $30.50 per share.
(in thousands)
Liquidity at
September 30, 2012
Borrowing base
$
270,000
Cash and cash equivalents
500
Long-term debt
(47,600)
Unused letters of credit
(350)
Liquidity
$
222,550 |
 F&D Costs Reconciliation (unaudited)
27
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.
2011 Reserve summary (MBoe)
Balance –
12/31/2010
50,715
Extensions & discoveries
25,548
Purchases
10,498
Revisions
(7,448)
Production
(2,338)
Balance –
12/31/2011
76,975
Cost summary ($M)
Acquisitions
$
93,251
Exploration costs
9,991
Development costs
182,522
Total
285,764
Finding & development costs ($/Boe)
All-in F&D costs
$
9.99
Drill-bit F&D cost
$
7.54
Reserve replacement ratio (%)
Extensions & discoveries (MBoe)
25,548
2011 Production (MBoe)
(2,338)
Reserve replacement
1,093%
3-Year reserve summary (MBoe)
Balance –
12/31/2008
35,178
Extensions & discoveries
34,386
Purchases
12,456
Revisions
318
Production
(5,363)
Balance –
12/31/2010
76,975
Finding & development costs ($/Boe)
3-year All-in F&D costs
$
10.15
3-year Drill-bit F&D cost
$
8.20
Reserve replacement ratio (%)
Extensions & discoveries (MBoe)
34,386
3-year Production (MBoe)
(5,363)
Reserve replacement
641%
Cost summary ($M)
Acquisitions
$
124,584
Exploration costs
14,348
Development costs
267,559
Total
$
406,491 |
 Contact
Information
MEGAN P. HAYS
Manager, Investor Relations & Corporate Communications
817.989.9000 x 2108
mhays@approachresources.com
www.approachresources.com |