Attached files
| file | filename |
|---|---|
| 8-K - 8-K - Approach Resources Inc | d880189d8k.htm |
| EX-99.1 - EX-99.1 - Approach Resources Inc | d880189dex991.htm |
 Fourth Quarter & Full-Year
2014 Results
FEBRUARY 25, 2015
Exhibit 99.2 |
 Fourth Quarter 2014 Results – February 2015
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 drilling project, 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 limited production experience with this
project, 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.
|
 Fourth Quarter 2014 Results – February 2015
Company overview
AREX OVERVIEW
ASSET OVERVIEW
Enterprise value $740MM
High-quality reserve base
Permian core operating area
2015 Capital program focused on flexibility and
returns
3
146 MMBoe proved reserves
66% Liquids, 38% oil
$1.4 BN proved PV-10
155,000 gross (136,000 net) acres
~1+ BnBoe gross, unrisked resource potential
~2,000 Identified HZ drilling locations targeting
Wolfcamp A/B/C
Running an average of 1 HZ rig in the Wolfcamp
shale play with a capital budget of approximately
$160 MM
Notes: Proved reserves and acreage as of 12/31/2014. 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
$8.64 per share on 2/17/2015, plus net debt as of 12/31/2014. See “PV-10
(unaudited)” slide. |
 Fourth Quarter 2014 Results – February 2015
Fourth quarter and full-year 2014 financial highlights
4
FY 2014
Q4 2014
Significant cash
flow and capex
below budget
Strong financial
position
Record revenue
and net income
•
Revenues of $258.5 MM (up 43% YoY)
•
Net income of $56.2 MM, or $1.42 per
diluted share
•
Adjusted net income (non-GAAP) of
$29.2 MM, or $0.74 per diluted share
•
Revenues of $55.1 MM (down 6% YoY
despite 25% YoY drop in oil prices)
•
Net income of $27.0 MM, or $0.68 per
diluted share
•
Adjusted net income (non-GAAP) of
$3.4 MM, or $0.08 per diluted share
•
EBITDAX (non-GAAP) of $188.3 MM (up
47% YoY), or $4.78 per diluted share
(up 46% YoY)
•
Capital expenditures of $393.5 MM,
below $400 MM capex guidance
•
EBITDAX (non-GAAP) of $44.3 MM (up
8% YoY), or $1.12 per diluted share (up
7% YoY)
•
Capital expenditures of $92.9 MM
•
Borrowing base increased to $600 MM during 4Q14, with elected commitments of $450
MM
•
34% Debt-to-capital ratio
Note:
See
“Adjusted
Net
Income,”
“EBITDAX”
and
“Strong,
Simple
Balance
Sheet”
slides.
•
Liquidity
of
$300
MM
at
December
31
st |
 Fourth Quarter 2014 Results – February 2015
Strong, simple balance sheet
5
AREX Liquidity and Capitalization
•
Following the Fall 2014 redetermination, the borrowing
base under our $1 billion revolving credit facility was
increased to $600 million, with a company-elected
commitment limit of $450 million
•
Provides a sizable cushion against more conservative bank
lending framework
•
Manageable Debt / LTM EBITDAX of 2.1x
•
LTM EBITDAX / LTM Interest of 8.7x, well above minimum
2.5x covenant requirement
•
Simple balance sheet with no near-term debt maturities
AREX Debt Maturity Schedule ($ MM)
AREX Capitalization as of 12/31/2014 ($ MM)
Cash
$0.4
Credit Facility
150.0
7.0% Senior Notes due 2021
250.0
Total Long-Term Debt
$400.0
Shareholders’
Equity
774.3
Total Book Capitalization
$1,174.3
AREX Liquidity as of 12/31/2014
Borrowing Base
$450.0
Cash and Cash Equivalents
0.4
Borrowings under Credit Facility
(150.0)
Undrawn Letters of Credit
(0.3)
Liquidity
$300.1
$300 MM undrawn
borrowing capacity
7.0% Senior Notes
$150.0
$250.0
$0.0
$50.0
$100.0
$150.0
$200.0
$250.0
$300.0
$350.0
$400.0
$450.0
2015
2016
2017
2018
2019
2020
2021 |
 Fourth Quarter 2014 Results – February 2015
Valuation and leverage well supported by proved reserve base
6
•
12/31/2014 reserve summary prepared by DeGolyer and MacNaughton
(“D&M”) •
Replaced
819%
of
produced
reserves
at
a
drill-bit
F&D
cost
of
$8.94
per
Boe
1
•
Total proved reserves up 27% YoY, proved oil reserves up 20% YoY
•
PV-10 up 25% YoY to a record $1.4 billion
Oil (MBbls)
NGLs (MBbls)
Natural Gas (MMcf)
Total (MBoe)
PV-10
($
MM)
2
PDP
17,599
18,319
133,583
58,181
$870.0
PDNP
379
763
5,378
2,039
$12.4
PUD
37,360
21,825
161,059
86,028
$530.6
Total Proved
55,338
40,907
300,020
146,248
$1,413.0
Total Proved Reserves
Reserves by Commodity
Proved PV-10
1. Drill-bit
F&D
costs
are
calculated
by
dividing
the
sum
of
exploration
costs
and
development
costs
for
the
year
by
the
total
of
reserve
extensions
and
discoveries
for
the
year.
2. PV-10 calculated based on the first-of-the-month, 12-month
average prices for oil, NGLs and natural gas, of $94.56 per Bbl of oil, $31.50 per Bbl of NGLs and $4.55 per MMBtu of natural gas.
38%
28%
34%
Oil
NGLs
Natural Gas
62%
< 1%
38%
PDP
PDNP
PUD
40%
1%
59%
PDP
PDNP
PUD |
 Fourth Quarter 2014 Results – February 2015
Fourth quarter and full-year 2014 operating highlights
7
FY 2014
Q4 2014
Low cost, on
time, and on
budget
Higher well
recoveries and
advancing
delineation
Solid execution
•
Completed
64
HZ
wells
•
Total production 5,049 MBoe vs early
guidance of 4,790 MBoe
•
2014 oil production of 5,545 Bbl/d (up
40% YoY)
•
Completed
13
HZ
wells
•
Total production 1,390 MBoe
•
4Q14 oil production of 5,902 Bbl/d (up
14% YoY and 7% QoQ)
•
FY2014 capex of $394 MM ($364 MM
D&C) vs $400 MM budget
•
Cash operating cost of $14.36/Boe
(down 7% YoY)
•
Q4 2014 capex of $93 MM ($87 MM
D&C)
•
Cash operating cost of $13.47/Boe
(down 21% YoY)
•
Strong well results from the Baker and
Elliott areas demonstrate upside
potential of central and eastern acreage
•
4Q14 HZ Wolfcamp B/C average IP 795
Boe/d |
 Fourth Quarter 2014 Results – February 2015
Well prepared for commodity price cycle
8
Key areas of focus in 2015
•
Plan to stay nimble in 2015 with key focus on financial discipline and
returns •
Capital budget of ~$160 MM is flexible
•
No
significant
drilling
or
service
contract
obligations
–
capital
budget
can
be
cut
further
•
Plan to time and size the development budget based on magnitude of service cost
reductions and direction of commodity prices
•
Delayed all completion and new well hook-ups in Q1 to March 2015 (no new wells
hooked into sales since mid- December)
•
Ability to sell new production volumes at a meaningful premium vs January
prices •
Operating team’s top priority is service cost reduction
•
Expect
reduction
of
15%
-
20%
in
D&C
costs
in
second
quarter
2015
•
Lower D&C costs significantly improves break-even price threshold
•
Water recycle center to be fully operational by end of Q1 2015
•
Strong balance sheet ensures financial flexibility
•
Debt
/
LTM
EBITDAX
of
2.1x
–
top
tier
for
SMID
cap
E&P
universe
•
Liquidity of $300 MM at 12/31/2014
•
Borrowing base of $600 MM vs elected commitment of $450 MM provides further
protection to liquidity •
Solid hedge book in place for 2015 |
 Fourth Quarter 2014 Results – February 2015
Strong track record of reserve growth
9
RESERVE GROWTH
OIL RESERVE GROWTH
•
YE14 reserves up 27% YoY
•
Replaced 819% of produced reserves at a
drill-bit F&D cost of $8.94/Boe
•
124.8 MMBoe proved reserves booked to HZ
Wolfcamp play
•
Strong, organic oil reserve growth driven by
HZ
Wolfcamp shale
•
Oil reserves up 20% YoY
•
Oil
reserves
up
11x
since
YE10
Note: See
“Drill-bit
F&D
cost
(unaudited)”
slide.
MMBoe
MMBbls
0
20
40
60
80
100
120
140
160
2004
20052006
20072008
20092010
20112012
20132014
Gas (MMBoe)
Oil & NGLs (MMBbls)
5.0
18.1
37.3
46.1
55.3
0
10
20
30
40
50
60
2010
2011
2012
2013
2014
Oil (MMBbls) |
 Fourth Quarter 2014 Results – February 2015
Strong track record of production growth
10
PRODUCTION GROWTH
OIL PRODUCTION GROWTH
•
2014 Production increased 47% YoY
•
Targeting 10-14% production growth in 2015
•
Strong, organic oil production growth driven
by HZ Wolfcamp shale
•
Oil production up 40% YoY
•
Oil
production
up
over
8x
since
FY10
MBbls
MBoe/d
0.0
2.0
4.0
6.0
8.0
10.0
12.0
14.0
16.0
2004
2005
2006
2007
2008
2009
2010
20112012
2013
2014
Natural Gas (MBoe/d)
Oil & NGLs (Mbbls/d)
246
482
969
1,444
2,024
0
500
1,000
1,500
2,000
2,500
2010
2011
2012
2013
2014
Oil (MBbls) |
 Fourth Quarter 2014 Results – February 2015
Outperformance in gas/NGL volumes achieves higher reserve
recovery and drives production growth
11
Horizontal Wolfcamp Production by Commodity
Mboe
96% oil growth since 3Q13
159% growth in HZ Wolfcamp
production since 3Q13
248% NGL growth since 3Q13
269% gas growth since 3Q13
427
687
715
957
1,004
1,108
85
135
166
247
270
312
82
128
153
230
259
286
260
424
396
481
475
510
0
200
400
600
800
1,000
1,200
3Q13
4Q13
1Q14
2Q14
3Q14
4Q14
Gas
NGLs
Oil |
 Fourth Quarter 2014 Results – February 2015
12
AREX HZ WOLFCAMP (BOE/D)
Note:
Daily
production
normalized
for
operational
downtime.
Gas
EUR
is
unprocessed
wellhead
volume.
AREX HZ Wolfcamp Well Performance
Oil EUR = 230 MBBL
Well EUR = 510 MBOE
Gas EUR = 1,271 MMCF
Average
GOR
=
5,000
–
6,000
Average Oil
Average BOE
Average Gas
Average GOR
N = 93 Wells
AREX Wolfcamp Horizontal Type Curve
Year-end 2014 |
 Probability
Distribution
of
AREX
93
Type
Curve
Wells
at
Year-end
2014
13 |
 Fourth Quarter 2014 Results – February 2015
14
Midland Basin -
Wolfcamp Horizontal Well Activity
Southern
Midland Basin
Northern
Midland Basin
18.3%
Northern
Midland Basin
81.7%
Southern Midland Basin
Source: DrillingInfo and IHS |
     Fourth Quarter 2014 Results – February 2015
15
Midland Basin -
IP and Drilling & Completion Cost
Source: Company releases/presentations, DrillingInfo, IHS, public databases, and
internal studies. Note: Three-stream IP estimated using 0.1539 Bbl per Mcf
and 25% shrinkage factor. 18% with
IP > 1,000
BOE
5% with
IP > 1,500
BOE
Entire Midland
Basin Average IP
689 BOE
Southern
Midland Basin
Northern Midland
Basin
$0
$2
$4
$6
$8
$10
$12
Actual Cost
Target Cost |
 Fourth Quarter 2014 Results – February 2015
Proven track record of delivering lowest D&C cost in the
Midland Basin
16
Approach’s annual average horizontal well D&C cost
Demonstrated 35%
improvement 2011-2014
$ MM
15% –
20%
reduction target
$8.6
$7.0
$5.8
$5.5
$0.0
$1.0
$2.0
$3.0
$4.0
$5.0
$6.0
$7.0
$8.0
$9.0
2011
2012
2013
2014
Q2 2015 Target |
 Fourth Quarter 2014 Results – February 2015
D&C Cost reductions will significantly improve profitability
17
Note: HZ Wolfcamp economics assume $4.00/Mcf realized natural gas price and NGL
price based on 40% of realized oil price. IRR at NYMEX strip
pricing
0%
10%
20%
40%
50%
60%
70%
$40
$50
$60
$70
$80
$90
Realized Oil Price ($/Bbl)
$4.1MM D&C
$4.6MM D&C
$5.1MM D&C
$5.5MM D&C
30% |
 Fourth Quarter 2014 Results – February 2015
Established infrastructure in place is critical to low cost structure
18
Benefits of water recycling
Pangea
West
North & Central Pangea
South
Pangea
Schleicher
Crockett
Irion
Reagan
Sutton
Recently completed
water recycling facility
329,000 Bbl Capacity
•
Reduce D&C cost
•
Reduce LOE
•
Increase project profit margin
•
Minimize fresh water use, truck
traffic and surface disturbance |
 Fourth Quarter 2014 Results – February 2015
19
AREX Flowback and Produced Water Recycle Facility
•
Reduce drilling and completion
cost by $450K per well
•
Reduce LOE by up to $1.00 per
BOE
•
Eliminate usage of potable fresh
water for completion
•
Minimize surface disturbance
•
Skim oil sale up to 200 Bbls per
day -
more than sufficient to pay
for facility operating expense
329,000 Bbl Capacity Facility
32,000
BBL
Treated
Water
Tank
32,000
BBL Dirty
Water
Tank
63,000 BBL
Treated
Water
Tank
63,000 BBL
Treated
Water
Tank
63,000 BBL
Treated
Water
Tank
32,000
BBL
Treated
Water
Tank
44,000 BBL
Treated
Water
Tank
32,000
BBL
Treated
Tank
Water
Skim Oil Sales
Flowback
& Produced Water Offloading
Terminal & Separation Facility
Flowback & Produced Water Supply
90 BPM
Pump Station
Water Treatment
&
Filtration Facility
|
 Fourth Quarter 2014 Results – February 2015
AREX Horizontal Wolfcamp activity
20
Note: Acreage as of 12/31/2014.
•
19,000 gross acres
•
Pad
drilling
with
AB
and
AC
“stacked”
wellbores
•
18 horizontal wells drilled to date
•
47,000 gross acres
•
Legacy gas/NGL field
•
No horizontal Wolfcamp
locations assigned to this
leasehold
•
89,000 gross acres
•
Pad drilling with AC and BC
“stacked”
wellbores
•
131 horizontal wells drilled to date
Legend
HZ Producer
HZ –
Waiting on Completion
NORTH &
CENTRAL PANGEA
PANGEA WEST
SOUTH
PANGEA |
 Fourth Quarter 2014 Results – February 2015
Baker 122HC and Elliott 129HC drilled in 2014 have validated
significant upside potential of AREX’s portfolio
21
2014 HZ Wolfcamp activity
Well performance
Over 40,000 gross acres
delineated by these
recent C-bench wells
HZ Producer
HZ –
Waiting on Completion
0
100
200
300
400
500
600
700
800
900
Day
9
19
29
39
49
59
69
79
89
99
109
Elliot 129HC
Baker 1AW 122HC
510 Mboe Typecurve
Legend
Elliott 129HC
Baker 122HC
•
IP: 827 Boe/d
•
IP oil: 70%
•
IP: 806 Boe/d
•
IP oil: 63% |
 Fourth Quarter 2014 Results – February 2015
Current hedge position
22
Commodity & Period
Contract Type
Volume
Contract Price
Crude Oil
January 2015 –
March 2015
Collar
1,500 Bbls/d
$85.00/Bbl -
$95.30/Bbl
January 2015 –
December 2015
Collar
1,600 Bbls/d
$84.00/Bbl -
$91.00/Bbl
January 2015 –
December 2015
Collar
1,000 Bbls/d
$90.00/Bbl -
$102.50/Bbl
January 2015 –
December 2015
3-way Collar
500 Bbls/d
$75.00/Bbl -
$84.00/Bbl -
$94.00/Bbl
January 2015 –
December 2015
3-way Collar
500 Bbls/d
$75.00/Bbl -
$84.00/Bbl -
$95.00/Bbl
Natural Gas
January 2015 –
June 2015
Collar
80,000 MMBtu/month
$4.00/MMBtu -
$4.74/MMBtu
January 2015 –
December 2015
Swap
200,000 MMBtu/month
$4.10/MMBtu
January 2015 –
December 2015
Collar
130,000 MMBtu/month
$4.00/MMBtu -
$4.25/MMBtu
•
Based on the midpoint of current 2015 guidance, approximately 64% of forecasted oil
production and 44% of forecasted
natural
gas
production
are
hedged
at
weighted
average
floor
prices
of
$80.59/Bbl
and
$4.05/MMBtu, respectively. |
 Fourth Quarter 2014 Results – February 2015
Production and expense guidance
23
2015 Guidance
Production
Oil (MBbls)
2,200 –
2,325
NGLs (MBbls)
1,575 –
1,625
Natural Gas (MMcf)
10,050 –
10,200
Total (MBoe)
5,450 –
5,650
Operating costs and expenses (per Boe)
Lease operating
$6.00 -
$7.00
Production and ad valorem taxes
7.25% of oil & gas revenues
Cash general and administrative
$3.75 -
$4.25
Exploration (non-cash)
$0.50 -
$1.00
Depletion, depreciation and amortization
$20.00 -
$22.00
Capital expenditures (in millions)
~$160 |
 Appendix |
 Fourth Quarter 2014 Results – February 2015
AREX Wolfcamp acreage is offset by large operators
25 |
 Fourth Quarter 2014 Results – February 2015
Adjusted net income (unaudited)
26
(in thousands, except per-share amounts)
Three Months Ended
December 31,
2014
2013
Net income
$
26,987
$
64,321
Adjustments for certain items:
Unrealized (gain) loss on commodity derivatives
(36,907)
1,348
Gain on sale of equity method investment
-
(90,743)
Related income tax effect
13,287
33,076
Adjusted net income
$
3,367
$
8,002
Adjusted net income per diluted share
$
0.08
$
0.20
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
(loss) for the three months ended December 31, 2014 and 2013. |
 Fourth Quarter 2014 Results – February 2015
EBITDAX (unaudited)
27
We
define
EBITDAX
as
net
income
(loss),
plus
(1)
exploration
expense,
(2)
gain
on
the
sale
of
our
equity
method
investment,
(3)
depletion,
depreciation
and
amortization
expense,
(4) share-based compensation expense, (5) unrealized loss (gain) on commodity
derivatives, (6) interest expense and (7) 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
(loss)
for
the
three
and
twelve
months
ended
December
31,
2014
and
2013.
(in thousands, except per-share amounts)
Three Months Ended
December 31,
2014
2013
Net income
$
26,987
$
64,321
Exploration
236
228
Gain on sale of equity method investment
-
(90,743)
Depletion, depreciation and amortization
28,664
22,005
Share-based compensation
2,521
512
Unrealized (gain) loss on commodity derivatives
(36,907)
1,348
Interest expense, net
5,715
5,225
Income tax provision
17,102
38,207
EBITDAX
$
44,318
$
41,103
EBITDAX per diluted share
$
1.12
$
1.05
Twelve Months Ended
December 31,
2014
2013
$
56,172
$
72,256
3,831
2,238
-
(90,743)
106,802
76,956
8,247
5,901
(42,113)
4,596
21,651
14,084
33,692
42,507
$
188,282
$
127,795
$
4.78
$
3.28 |
 Fourth Quarter 2014 Results – February 2015
F&D costs (unaudited)
28
F&D Cost reconciliation
Cost summary (in thousands)
Property acquisition costs
Unproved properties
$
4,578
Proved properties
-
Exploration costs
3,831
Development costs
382,995
Total costs incurred
$
391,404
Reserves summary (MBoe)
Balance –
12/31/2013
114,661
Extensions & discoveries
43,247
Production (1)
(5,281)
Revisions to previous estimates
(6,379)
Balance –
12/31/2014
146,248
F&D cost ($/Boe)
All-in F&D cost
$
10.62
Drill-bit F&D cost
8.94
Reserve replacement ratio
Drill-bit
819%
(1) Production includes 1,390 MMcf related to field fuel.
All-in
finding
and
development
(“F&D”)
costs
are
calculated
by
dividing
the
sum
of
property acquisition costs, exploration costs and development costs for the year by
the sum of reserve extensions and discoveries, purchases of minerals in
place and total revisions for the year.
Drill-bit
F&D
costs
are
calculated
by
dividing
the
sum
of
exploration
costs
and
development costs for the year by the total of reserve extensions and discoveries
for the year.
We believe that providing F&D cost is useful to assist in 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
accordancewith
GAAP
(including
the
notes),
included
in
our
previous
SEC filings and to be included in our annual report on Form 10-K to be filed
with the SEC on February 26, 2015. 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
used by us 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 table reconciles our estimated F&D costs for 2014 to the
information required by paragraphs 11 and 21 of ASC 932-235.
|
 Fourth Quarter 2014 Results – February 2015
PV-10 (unaudited)
29
The present value of our proved reserves, discounted at 10%
(“PV-10”), was estimated at $1.4 billion at December 31, 2014, and was calculated based on the first-of-the-month,
twelve-month
average
prices
for
oil,
NGLs
and
gas,
of
$94.56
per
Bbl
of
oil,
$31.50
per
Bbl
of
NGLs
and
$4.55
per
MMBtu
of
natural
gas.
PV-10 is our estimate of the present value of future net revenues from proved
oil and gas reserves after deducting estimated production and ad valorem taxes, future capital costs
and operating expenses, but before deducting any estimates of future income taxes.
The estimated future net revenues are discounted at an annual rate of 10% to determine their
“present value.”
We believe PV-10 to be an important measure for evaluating the relative
significance of our oil and gas properties and that the presentation of the non-GAAP
financial measure of PV-10 provides useful information to investors because it
is widely used by professional analysts and investors in evaluating oil and
gas companies. Because there are many unique factors that can impact an
individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is
valuable for evaluating the Company. We believe that PV-10 is a financial
measure routinely used and calculated similarly by other companies in the oil and gas industry.
The following table reconciles PV-10 to our standardized measure of discounted
future net cash flows, the most directly comparable measure calculated and presented in accordance
with GAAP. PV-10 should not be considered as an alternative to the
standardized measure as computed under GAAP. (in millions)
December 31,
2014
PV-10
$
1,413
Less income taxes:
Undiscounted future income taxes
(1,267)
10% discount factor
910
Future discounted income taxes
(357)
Standardized measure of discounted future net cash flows
$
1,056 |
 Contact information
SERGEI KRYLOV
Executive Vice President & Chief Financial Officer
817.989.9000
ir@approachresources.com
www.approachresources.com |