 Approach Resources Inc.
INVESTOR PRESENTATION
MARCH 2013
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 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.
|
 Company Overview
•
Enterprise value $1.1 BN
•
High quality reserve base
95.5 MMBoe proved reserves
99% Permian Basin
•
Permian core operating area
167,000 gross (148,000 net) acres
1+ BnBoe gross, unrisked resource
2,000+ Identified HZ drilling locations
•
2013 Capital program of $260 MM
Running 3 HZ rigs in the Wolfcamp shale
Targeting 30%+ production growth
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 $24.43 per share on 3/1/2013, plus
net debt as of 12/31/2012. play
potential
targeting the Wolfcamp oil shale play
|
 2012 Highlights
•
Oil-driven reserves
4
Notes:
See
“F&D
Costs
Reconciliation”
slide
in
appendix.
•
YE’12 proved reserves total 95.5 MMBoe, up 24% over YE’11
•
Oil proved reserves total 37.3 MMBbls, up 106% over YE’11
•
Oil-driven production growth
•
Production totaled 7.9 MBoe/d, up 24% over 2011 and hit the mid-point of
guidance range •
Oil production doubled from 2011 to 969 MBbls
•
Oil production has tripled since 2009
•
Competitive reserve replacement and finding costs
•
Drill-bit reserve replacement of 1,346%
•
Drill-bit finding and development cost of $7.45/Boe
•
Horizontal Wolfcamp delivering strong results, well costs coming
down
•
Delineated 107,000 gross acres
•
Transitioned
Wolfcamp
“B”
to
development
mode
•
2H’12 average D&C cost approx. $6.4 MM
•
Expect to achieve target D&C cost of $5.5 MM in 2Q’13
growth |
 Reserve Growth
5
RESERVE GROWTH
OIL RESERVE GROWTH
•
YE’12 reserves up 24% YoY
•
Replaced 1,346% of reserves at a drill-bit F&D
cost of $7.45/Boe
•
60.1 MMBoe proved reserves booked to
Wolffork/Wolfcamp oil shale play
•
Strong organic reserve growth driven by oil
from HZ Wolfcamp shale
•
Oil reserves up 7x
since YE’09
•
Oil reserves up 106%
YoY
PD Oil reserves up 60%
YoY
Launched
Wolfcamp Study
Announced
Vertical Wolfcamp
Pilot Results
Began HZ
Wolfcamp Pilot
Program
Strong HZ Wolfcamp Results;
Prepare for Large-Scale
Development
120
100
80
60
40
20
0
2004
2005
2006
2007
2008
2009
2010
2011
2012
Natural Gas (MMBoe)
Oil & NGLs (MMbbls)
2009
2010
2011
2012
40
35
30
20
15
10
0
5
25
Oil (MMBbls)
Notes: See “F&D Costs Reconciliation” slide in appendix.
|
 Production Growth
6
PRODUCTION GROWTH
OIL PRODUCTION GROWTH
•
2012 production increased 24% YoY
•
Targeting 30%+ production growth in 2013
•
Strong organic production growth driven by
oil from horizontal Wolfcamp shale
•
Oil production up 3x
since 2009
•
Oil production up 101%
over 2011
3.6 MMBoe –
3.9 MMBoe in 2013
2013E Production mix ~70% liquids
9.0
8.0
7.0
6.0
5.0
4.0
3.0
2.0
1.0
0.0
2004
2005
2006
2007
2008
2009
2010
2011
2012
Natural Gas (Mboe/d)
Oil & NGLs (Mbbls/d)
1200
1000
800
600
400
200
0
2009
2010
2011
2012
Oil (MBbls) |
 Low-Cost Operator
FY’12 LOE ($/Boe)
3-YR AVERAGE F&D COSTS ($/Boe)
LEASE OPERATING EXPENSE ($/Boe)
7
2010-2012 Drill-Bit F&D
Cost ($/Boe)
$20.00
$18.00
$16.00
$14.00
$12.00
$10.00
$8.00
$6.00
$4.00
Peer 1
AREX
Peer 2
Peer 3
Peer 4
Peer 5
Peer 6
Peer 7
Peer 8
Peer 1
AREX
Peer 2
Peer 3
Peer 4
Peer 5
Peer 6
Peer 7
Peer 8
$18.00
$16.00
$14.00
$12.00
$10.00
$8.00
$6.00
$4.00
Notes: Peers include CXO, FANG, KOG, LPI, OAS, PXD, ROSE and SM. Data based on SEC filings for
twelve months ending December 31, 2012, except for LPI. LPI LOE data based on trailing
twelve months ending September 30, 2012. |
 AREX Wolfcamp Oil Shale Resource Play
8
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
Source: Rig data from Scotia Waterous.
HZ Wolfcamp resource potential up 300%+
2013 Operations
Broad industry participation de-risking play
42 HZ Wolfcamp shale rigs as of September
2012
940+ MMBoe gross, unrisked resource potential
Plan to drill ~ 35 to 40 HZ wells with 3 rigs
2,096 Identified HZ Wolfcamp locations targeting
the Wolfcamp A, B & C
Testing “stacked-lateral”
development and tighter
well spacing
Decrease well costs and increase efficiencies
when field infrastructure projects are
completed |
 AREX Drilling Locations, Targets & Resource Potential
9
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 |
 Wolfcamp Oil Shale Play
10
WOLFCAMP SHALE – WIDESPREAD, THICK, CONSISTENT & REPEATABLE
|
 Horizontal Wolfcamp –
82% of IP is Oil
11
Source: Publicly available regulatory filings, company presentations.
Average Oil = 82%
Total Data Points = 67 wells |
 Misconception vs. Facts
12
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 |
 CT K
1901 AREX HZ Wolfcamp Activity
13
Legend
Vertical Producer
HZ Producer
HZ –
Waiting on Completion
HZ –
Drilling
HZ –
Permit
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 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 14
0
100
200
300
400
500
600
700
800
900
1,000
1,100
1,200
0
60
120
180
240
300
360
420
480
Daily Production Data from
AREX Recent 7 Horizontal Wells
450 MBoe Type Curve
B Bench well data
45 A 701H
45 D 902H
45 C 803H
45 B 2401H
45 E 1101H
45 F 2301H
45 F 2302H
45 C 805H
45 C 804H
45 F 2303H
45 F 2304H
45 A 703H
45 B 2403H
45 B 2402H
CT J 1003H
45 C 806H
PW 6507H
PW 6601H
PW 6602H
B Bench Wells
A Bench Wells
Legend
A Bench well data
450 MBoe Type
Curve
Daily Production Data from
AREX A Bench Wells
45 E 1102H
45 G 2208H
45 G 2209H
45 G 2216H
45 G 2217H
Baker B 206H
Baker B 207H
Recent B bench well
data from 7 wells
Time (Days)
45 D 905H
CONTINUED STRONG WELLS RESULTS – TRACKING ABOVE THE TYPE CURVE
|
 Wolfcamp Stacked Pay Zones
15
AREX Baker A 112
HZ WOLFCAMP
TARGET
Wolfcamp
A
Wolfcamp
B
Wolfcamp
C
Identified locations
703
690
703
EUR (MBoe)
450
450
450
Gross Resource
Potential (MMBoe)
316
310
316
940+ MMBoe Total Gross
Resource Potential
Wolfcamp A
Wolfcamp B
Wolfcamp C
Wolfcamp
Top
Notes: Identified locations based on multi-bench development and 120-acre
spacing. No locations assigned to south Project Pangea. HZ TARGETS &
RESOURCE POTENTIAL 5800
5500
5600
5700
5900
6000
6100
6200
6300
6400
6500
0
200
GR API
0.2
2,000
MSFL OHMM
0.2
2,0000.3
LLD OHMM
0.3
0.1
NPHI
0.1
DPHI
0.2
0
Free Hydrocarbon
0.2
0
BVW
20
200
20
200 |
 AREX HZ Wolfcamp Economics
16
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. •
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
80
70
60
50
40
30
20
10
0
350
400
450
500
550
Well EUR (Mboe)
$100 / bbl
$90 / bbl
$80 / bbl
$70 / bbl
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 |
 Infrastructure for Large-Scale Development
17
•
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
18
•
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
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
wells |
 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
19
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 |
 2012 Financial Highlights
21
Notes:
See
“Adjusted
Net
Income,”
“EBITDAX”
and
“Liquidity”
slides
in
appendix.
REVENUES, EARNINGS & CASH FLOW
BALANCE SHEET & LIQUIDITY
•
Revenues of $128.9 MM in 2012 vs. $108.4 MM in 2011
•
Net income of $6.4 MM or $0.18 per diluted share
Adjusted net income (non-GAAP) of $3.8 MM or $0.11 per diluted share
EBITDAX (non-GAAP) of $83.0 MM or $2.37 per diluted share
•
Cash flow from operating activities of $90.6 MM
•
Borrowing base of $280 MM
•
YE’12 debt of $106 MM
•
YE’12 liquidity of $174.4 MM
Long-term debt-to-capital of 14.3% |
 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:
22
•
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
$280 MM borrowing base strengthens liquidity |
 2013 Operating and Financial Guidance
23
2013 GUIDANCE
2013 Guidance
Production
Total (MBoe)
3,600 –
3,900
Percent Oil & NGLs
70%
Operating costs and expenses ($/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
24
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 |
 Adjusted Net Income (unaudited)
25
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
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
Adjustments for certain items:
Impairment
—
18,476
Unrealized (gain) loss on commodity derivatives
(3,874)
347
Gain on sale of oil & gas properties
—
(248)
Related income tax effect
1,317
(6,316)
Adjusted net income
$
3,827
$
19,501
Adjusted net income per diluted share
$
0.11
$
0.67 |
 EBITDAX (unaudited)
26
(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
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).
|
 Liquidity
27
Liquidity
(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.
(in thousands)
December 31, 2012
Long-term debt
$
106,000
Total stockholders’
equity
633,468
739,468
Long-term debt-to-capital
14.3%
(in thousands)
December 31, 2012
Borrowing base
$
280,000
Cash and cash equivalents
767
Long-term debt
(106,000)
Unused letters of credit
(325)
Liquidity
$
174,442
debt (GAAP). We use the long-term debt-to-capital ratio as a measurement of our overall
financial leverage. However, this ratio has limitations. This ratio can vary from
year-to-year for the Company and can vary among companies based on what is or is not included in the ratio on a company’s financial statements.
This ratio 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.
Long-term
debt-to-capital
ratio
(unaudited)
is
calculated
by
dividing
long-term
debt
(GAAP)
by
the
sum
of
total
stockholders’
equity
(GAAP)
and
long-term |
 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 |