Attached files
| file | filename |
|---|---|
| 8-K - 8-K - Approach Resources Inc | d492591d8k.htm |
| EX-99.1 - EX-99.1 - Approach Resources Inc | d492591dex991.htm |
 Approach Resources Inc.
FULL YEAR & FOURTH QUARTER 2012 RESULTS
FEBRUARY 21, 2013
Exhibit 99.2 |
 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
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
$24.47
per
share
on
2/15/2013,
plus
net
debt
as
of
12/31/2012.
•
Enterprise value $1.1 BN
•
High quality reserve base
•
Permian core operating area
•
2013 capital program of $260 MM
Running 3 HZ rigs in the Wolfcamp shale
play
Targeting 30%+ production growth
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
95.5 MMBoe proved reserves
99% Permian Basin |
 2012 Financial Highlights
4
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
•
Cash flow from operating activities of $90.6 MM
•
Borrowing base of $280.0 MM
•
YE’12 debt of $106.0 MM
•
YE’12 liquidity of $174.4 MM
Long-term debt-to-capital of 14.3%
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
Notes: See “Adjusted Net Income,” “EBITDAX” and “Liquidity” slides in
appendix. |
 2012 Highlights
•
Oil-driven reserves
growth
•
Oil-driven production
growth
•
Competitive reserve replacement and finding costs
•
Horizontal Wolfcamp delivering strong results, well costs coming
down
5
•
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
•
Drill-bit reserve replacement of 1,346%
•
Drill-bit finding and development cost of $7.45/Boe
•
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
•
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
Notes: See “F&D Costs Reconciliation” slide in appendix. |
 Reserve Growth
6
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
horizontal Wolfcamp shale
•
Oil reserves up 7x
since YE’09
•
Oil reserves up 106%
YoY
Launched
Wolfcamp Study
Announced
Vertical Wolfcamp
Pilot Results
Began HZ
Wolfcamp Pilot
Program
Strong HZ Wolfcamp Results;
Prepare for Large-Scale
Development
Notes:
See
“F&D
Costs
Reconciliation”
slide
in
appendix.
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 (MBbls) |
 Production Growth
7
PRODUCTION GROWTH
OIL PRODUCTION GROWTH
•
2012 production increased 24% YoY
•
Targeting 30%+ production growth in 2013
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
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
Natural Gas (MBoe/d)
Oil & NGLs (Mbbls/d)
0
200
400
600
800
1000
1200
2009
2010
2011
2012
Oil (MBbls) |
 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%+
940+ MMBoe gross, unrisked resource potential
2,096 Identified HZ Wolfcamp locations targeting
2013 Operations
Plan to drill ~ 35 to 40 HZ wells with 3 rigs
Testing “stacked-lateral”
development and tighter
well spacing
Decrease well costs and increase efficiencies
when field infrastructure projects are
completed
42 HZ Wolfcamp shale rigs as of September
2012
Broad industry participation de-risking play
the Wolfcamp A, B & C |
 Wolfcamp Oil Shale Play
9
WOLFCAMP SHALE –
WIDESPREAD, THICK, CONSISTENT & REPEATABLE |
 Horizontal Wolfcamp –
82% of IP is Oil
10
Source: Publicly available regulatory filings, company presentations.
|
 AREX HZ Wolfcamp Activity
11
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
•
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
•
3-D Seismic acquisition completed.
Data processing in progress
•
Targeting HZ pilot well in 2Q’13
•
3-D seismic interpretation
completed
•
Drilling HZ pilot well
HZ –
Permit
Legend
Vertical Producer
HZ Producer
HZ –
Waiting on Completion
HZ –
Drilling |
 Horizontal Wolfcamp Well Performance
12
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)
CONTINUED
STRONG
WELLS
RESULTS
–
TRACKING
ABOVE
THE
TYPE
CURVE |
 13
Notes: Identified locations based on multi-bench development and 120-acre
spacing. No locations assigned to south Project Pangea. Wolfcamp
Stacked Pay Zones |
 AREX Wolfcamp Targets & Resource Potential
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
0
10
20
30
40
50
60
70
80
350
400
450
500
550
Well EUR (MBoe)
$100 / bbl
$90 / bbl
$80 / bbl
$70 / 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
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
15 |
 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:
17
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
$280.0 MM borrowing base strengthens liquidity
•
2013
Production
guidance
3.6
MMBoe
–
3.9
MMBoe
•
2013E Production mix 70% liquids
•
Targeting Wolfcamp A, B and C
•
Testing
“stacked”
lateral
development
concept |
 2013 Operating and Financial Guidance
18
2013 GUIDANCE
2013 Guidance
Production
Total (MBoe)
3,600
–
3,900
Percent Oil & NGLs
70%
Operating costs and expenses ($/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
19
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)
20
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)
21
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 |
 Liquidity
22
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. The table below summarizes our liquidity at December 31,
2012. Long-term debt-to-capital ratio (unaudited)
is calculated as of September 30, 2012, and by dividing long-term debt (GAAP)
by the sum of total stockholders’ equity (GAAP) and long-term 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. The table
below summarizes our long-term debt-to-capital ratio at December 31,
2012. (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 |
 F&D Costs Reconciliation (unaudited)
23
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)
Property 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% |
 Contact
Information
MEGAN P. HAYS
Manager, Investor Relations & Corporate Communications
817.989.9000 x2108
mhays@approachresources.com
www.approachresources.com |