Attached files
| file | filename |
|---|---|
| 8-K - 8-K - Approach Resources Inc | d921729d8k.htm |
| EX-99.1 - EX-99.1 - Approach Resources Inc | d921729dex991.htm |
 First Quarter 2015 Results
MAY 6, 2015
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.
First Quarter 2015 Results – May 2015
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.
|
 Company overview
AREX OVERVIEW
ASSET OVERVIEW
Enterprise value $804MM
High-quality reserve base
146 MMBoe proved reserves
66% Liquids, 38% oil
$1.4 BN proved PV-10
Permian core operating area
147,000 gross (134,000 net) acres
~1+ BnBoe gross, unrisked resource potential
~2,000 Identified HZ drilling locations targeting
Wolfcamp A/B/C
2015 Capital program focused on flexibility and
returns
Running an average of 1 HZ rig in the Wolfcamp
shale play with a capital budget of approximately
$160 MM
Note: Proved reserves as of 12/31/2014 and acreage as of 3/31/2015. 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
$8.48
per
share
on
5/5/2015,
plus
net
debt
as
of
3/31/2015.
See
“PV-10
(unaudited)”
slide.
3
First Quarter 2015 Results – May 2015 |
 1Q15 Key highlights
4
1Q15 HIGHLIGHTS
•
Drilled 8 and completed 13 HZ wells
•
Continued improvement on already best-in-
class HZ well costs
•
Increased 1Q15 production 21% YoY to 14.3
MBoe/d
•
Water recycle center now fully operational
•
Cash operating cost of $12.32/Boe, a 27%
improvement YoY
1Q15 SUMMARY RESULTS
Production (MBoe/d)
14.3
% Oil
38%
% Total liquids
67%
Average realized price ($/Boe)
Average realized price, excluding commodity derivatives impact
$
25.87
Average realized price, including commodity derivatives impact
38.23
Costs and expenses ($/Boe)
LOE
$
5.55
Production and ad valorem taxes
2.20
Exploration
0.85
General and administrative
6.30
G&A –
cash component
4.58
G&A –
noncash component
1.72
DD&A
20.61
Note:
See
“Cash
operating
expenses”
slide.
First Quarter 2015 Results – May 2015 |
 Well prepared for commodity price cycle
5
Key areas of focus in 2015
•
Plan to stay nimble in 2015 with key focus on financial discipline and
returns •
No significant drilling or service contract obligations
•
Plan to time and size the development budget based on magnitude of service cost
reductions and direction of commodity prices
•
Operating team’s top priority is service cost reduction
•
Current well AFEs at ~$4.6 MM
•
Lower D&C costs significantly improves break-even price threshold
•
Water recycle center became fully operational during March 2015
•
Strong balance sheet ensures financial flexibility
•
Debt / LTM EBITDAX of 2.6x
•
Liquidity of $240 MM at 3/31/2015
•
Borrowing base of $525 MM vs elected commitment of $450 MM provides further
protection to liquidity •
Solid hedge book in place for 2015
First Quarter 2015 Results – May 2015 |
 1Q15 Operating highlights
OPERATING HIGHLIGHTS
Maximizing
Returns
•
Successfully implemented cost reduction initiatives, current HZ well AFEs now
averaging $4.6 MM per well, down ~15% from 2014 average of $5.5 MM
•
D&C
cost
savings
includes
$450,000
per
well
of
permanent
savings
from
water
recycling
•
LOE of $5.55/Boe, improved 25% YoY
Tracking
Development
Plan
•
Drilled
8
HZ
wells
and
completed
13
HZ
wells
•
Wolfcamp
B
–
7
wells
and
Wolfcamp
C
–
6
wells
•
Recent HZ Wolfcamp average IP 723 Boe/d (56% oil, 80% liquids)
•
Overall HZ well results continue to track at or above increased 510 MBoe type
curve Delivering
Production
Growth
•
Total production 14.3 MBoe/d (up 21% YoY)
•
Oil production 5.5 Mbbl/d (up 10% YoY)
6
First Quarter 2015 Results – May 2015 |
 1Q15 Financial highlights
FINANCIAL HIGHLIGHTS
Preserving Cash
Flow
•
Quarterly EBITDAX (non-GAAP) of $33.4 MM, or $0.83 per diluted share
•
Capital expenditures of $74.6 MM ($68 million for D&C)
•
Remain well-hedged for the balance of 2015
Stable Financial
Position
•
Liquidity
of
$240MM
at
March
31
st
•
Lenders reaffirmed $450 MM commitment amount following Spring 2015
redetermination
Heightened
focus on cutting
costs
•
Revenues (pre-hedge) of $33.3 MM, adjusted net loss (non-GAAP) of $1.3 MM,
or $0.03 per diluted share
•
Every per-unit cash cost metric has been improved since 1Q14
•
1Q15 Cash operating costs totaled $12.32/Boe, a 27% decrease compared to
1Q14 Strong Balance Sheet and Liquidity to Develop
HZ Wolfcamp Shale
Note:
See
“Adjusted
Net
Income,”
“EBITDAX,”
“Strong,
Simple
Balance
Sheet,
and
“Cash
operating
expenses”
slides.
7
First Quarter 2015 Results – May 2015 |
 8
Winter storms and DCP plant turnaround impact 1H15
production by 120 –
160 MBoe
Winter storm
related downtime
~20 MBoe
1H15 Daily Production Detail
1
2
2
2
2
2
1Q15 Wells turned to sales
1Q15 Production = 1,287 MBoe
2Q15E Production ~ 1,300 –
1,400 MBoe
DCP Plant
turnaround
~75 –
115 MBoe
DCP Plant
maintenance
~25 MBoe
3
2
2Q15E Wells turned to sales
3
4
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
18,000
20,000
1/1
1/8
1/15
1/22
1/29
2/5
2/12
2/19
2/26
3/5
3/12
3/19
3/26
4/2
4/9
4/16
4/23
4/30
5/7
5/14
5/21
5/28
6/4
6/11
6/18
6/25
First Quarter 2015 Results – May 2015 |
 9
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
Skim Oil Sales
Flowback
& Produced Water Offloading
Terminal & Separation Facility
Flowback & Produced Water Supply
90 BPM
Pump Station
Water Treatment
&
Filtration Facility
63,000 BBL
Treated
Water
Tank
44,000 BBL
Treated
Water
Tank
N
63,000 BBL
Treated
Water
Tank
63,000 BBL
Treated
Water
Tank
32,000
BBL
Treated
Water
Tank
32,000
BBL
Treated
Water
Tank
32,000
BBL Dirty
Water
Tank
32,000
BBL
Treated
Water
Tank
First Quarter 2015 Results – May 2015 |
 10
Water recycling facility successfully started in March 2015
Recent Recycled Water Volumes
•
The
water
recycling
facility
was
ramped
up
during
March
2015
and
now
successfully
recycles
up
to
70+%
of
AREX daily flowback water volumes
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
0
5,000
10,000
15,000
20,000
25,000
30,000
3/21
3/28
4/4
4/11
First Quarter 2015 Results – May 2015 |
 Strong, simple balance sheet
11
AREX Liquidity and Capitalization
•
At March 31, 2015, we had a $1 billion senior secured
revolving credit facility in place, with aggregate lender
commitments of $450 MM and borrowing base of $600 MM
•
Following the Spring 2015 redetermination, our lenders
reaffirmed the commitment amount of $450 MM, while
reducing the borrowing base to $525 MM
•
A $75 MM cushion remains against more conservative bank
lending framework
•
Manageable Debt / LTM EBITDAX of 2.6x
•
LTM EBITDAX / LTM Interest of 8.0x, well above minimum
2.5x covenant requirement
•
Simple balance sheet with no near-term debt maturities
AREX Debt Maturity Schedule ($ MM)
AREX Capitalization as of 3/31/2015 ($ MM)
Cash
$0.3
Credit Facility
210.0
7.0% Senior Notes due 2021
250.0
Total Long-Term Debt
$460.0
Shareholders’
Equity
768.8
Total Book Capitalization
$1,228.8
AREX Liquidity as of 3/31/2015
Aggregate Commitment
$450.0
Cash and Cash Equivalents
0.3
Borrowings under Credit Facility
(210.0)
Undrawn Letters of Credit
(0.3)
Liquidity
$240.0
$240 MM undrawn
borrowing capacity
7.0% Senior Notes
$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
$210.0
$250.0
First Quarter 2015 Results – May 2015 |
 Valuation and leverage well supported by proved reserve base
12
•
12/31/2014 reserve summary prepared by DeGolyer and MacNaughton
•
Replaced 819% of produced reserves at a drill-bit F&D cost of $8.94 per
Boe¹ •
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 $4.55 per MMBtu of natural gas.
38%
28%
34%
40%
1%
59%
62%
< 1%
38%
Oil
NGLs
Natural Gas
PDP
PDNP
PUD
PDP
PDNP
PUD
First Quarter 2015 Results – May 2015 |
 13
Significant valuation upside potential from unproven resources and
commodity price recovery
Adjusted PV-10 vs Enterprise Value ($ billion)
Midland
Basin
Peer
EV/2015E
EBITDA
6
1
1.
Using SEC prices of $94.56/Bbl for WTI and $4.55/Mcf for Henry Hub.
2.
Based on NYMEX strip prices for WTI and Henry Hub as of 5/5/2015.
3.
Assumes D&C cost of $4.6MM per horizontal PUD well.
4.
1Q15 capex of $74.6MM.
5.
PV-10
as
of
12/31/14
is
reconciled
to
our
standardized
measure
of
discounted
future
cash
flows,
the
most
directly
comparable
measure
calculated
and
presented
in
accordance
with
GAAP,
on
slide
26.
Adjusted
PV-10 is calculated consistent with PV-10 as of 12/31/14, adjusted for the
following: (1) NYMEX strip prices as of 5/5/14, (2) D&C cost of $4.6MM per horizontal PUD well location, and (3) 1Q15 capex of
$74.6MM.
6.
Enterprise value/2015E EBITDA per FactSet consensus as of 5/5/2015. Peers
include CPE, FANG, LPI, PE, PXD, RSPP. 2
3
4
5
First Quarter 2015 Results – May 2015
$1.4
($0.7)
$0.1
$0.1
$0.8
$0.8
$0.0
$0.2
$0.4
$0.6
$0.8
$1.0
$1.2
$1.4
YE2014
Proved SEC
PV-10
Commodity
Price Decline
Impact
D&C Cost
Savings
Impact
1Q15 Net
Investment
Adjusted
Proved Enterprise
PV-10
Current
Value
5.1x
8.4x
10.9x
11.0x
13.9x
14.9x
18.2x
0.0x
2.0x
4.0x
6.0x
8.0x
10.0x
12.0x
14.0x
16.0x
18.0x
20.0x
AREX
Peer 1
Peer 2
Peer 3
Peer 4
Peer 5
Peer 6 |
 14
AREX HZ WOLFCAMP (BOE/D)
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
First Quarter 2015 Results – May 2015
Note: Daily production normalized for operational downtime. Gas EUR is unprocessed wellhead
volume. |
 Probability Distribution of AREX 93 Type Curve Wells at Year-end
2014
15
First Quarter 2015 Results – May 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
Achieved 16%
D&C cost
reduction
First Quarter 2015 Results – May 2015
$ MM
$8.6
$7.0
$5.8
$5.5
$4.6
$0.0
$1.0
$2.0
$3.0
$4.0
$5.0
$6.0
$7.0
$8.0
$9.0
2011
2012
2013
2014
Current AFE |
 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
First Quarter 2015 Results – May 2015
0%
10%
20%
30%
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 |
 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
First Quarter 2015 Results – May 2015 |
 Current hedge position
19
Commodity & Period
Contract Type
Volume
Contract Price
Crude Oil
April 2015 –
December 2015
Collar
1,600 Bbls/d
$84.00/Bbl -
$91.00/Bbl
April 2015 –
December 2015
Collar
1,000 Bbls/d
$90.00/Bbl -
$102.50/Bbl
April 2015 –
December 2015
3-way Collar
500 Bbls/d
$75.00/Bbl -
$84.00/Bbl -
$94.00/Bbl
April 2015 –
December 2015
3-way Collar
500 Bbls/d
$75.00/Bbl -
$84.00/Bbl -
$95.00/Bbl
Natural Gas
April 2015 –
June 2015
Collar
80,000 MMBtu/month
$4.00/MMBtu -
$4.74/MMBtu
April 2015 –
December 2015
Swap
200,000 MMBtu/month
$4.10/MMBtu
April 2015 –
December 2015
Collar
130,000 MMBtu/month
$4.00/MMBtu -
$4.25/MMBtu
•
Based on the midpoint of current 2015 guidance, approximately 56% of forecasted 2Q15-4Q15 oil
production and 42% of forecasted natural gas production are hedged at weighted average floor
prices of $79.83/Bbl and $4.06/MMBtu, respectively.
First Quarter 2015 Results – May 2015 |
 Production and expense guidance
20
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
First Quarter 2015 Results – May 2015 |
 Appendix |
 Adjusted net income (unaudited)
22
(in thousands, except per-share amounts)
Three Months Ended
March 31,
2015
2014
Net (loss) income
$
(7,708)
$
2,945
Adjustments for certain items:
Unrealized loss on commodity derivatives
9,321
5,926
Rig termination fees
498
-
Related income tax effect
(3,437)
(2,015)
Adjusted net (loss) income
$
(1,326)
$
6,856
Adjusted net (loss) income per diluted share
$
(0.03)
$
0.17
The amounts included in the calculation of adjusted net (loss) income and adjusted net (loss) 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
(loss) income to net income for the three months ended March 31, 2015 and 2014.
ADJUSTED NET (LOSS) INCOME (UNAUDITED)
First Quarter 2015 Results – May 2015 |
 EBITDAX (unaudited)
23
EBITDAX (UNAUDITED)
The
amounts
included
in
the
calculation
of
EBITDAX
were
computed
in
accordance
with
GAAP.
EBITDAX
is
not
a
measure
of
net
income
or
cash
flow as determined by GAAP. EBITDAX is presented herein and reconciled to the GAAP
measure of net income because of its wide acceptance by the
investment
community
as
a
financial
indicator
of
a
company's
ability
to
internally
fund
development
and
exploration
activities.
This
measure
is
provided
in
addition
to,
and
not
as
an
alternative
for,
and
should
be
read
in
conjunction
with,
the
information
contained
in
our
financial
statements
prepared
in
accordance
with
GAAP
(including
the
notes),
included
in
our
SEC
filings
and
posted
on
our
website.
The following table provides a reconciliation of EBITDAX to net income for the
three months ended March 31, 2015 and 2014. (in thousands, except
per-share amounts) Three Months Ended
March 31,
2015
2014
Net (loss) income
$
(7,708)
$
2,945
Exploration
1,090
738
Depletion, depreciation and amortization
26,520
23,606
Share-based compensation
2,217
2,654
Unrealized loss on commodity derivatives
9,321
5,926
Interest expense, net
5,922
5,137
Income tax (benefit) provision
(3,996)
1,681
EBITDAX
$
33,366
$
42,687
EBITDAX per diluted share
$
0.83
$
1.09
First Quarter 2015 Results – May 2015 |
 F&D costs (unaudited)
24
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%
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
accordance with 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.
(1) Production includes 1,390 MMcf related to field fuel.
First Quarter 2015 Results – May 2015 |
 PV-10 (unaudited)
25
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
First Quarter 2015 Results – May 2015 |
 Cash operating expenses
26
Cash operating expenses
We define cash operating expenses as operating expenses, excluding (1) exploration
expense, (2) depletion, depreciation and amortization expense and (3)
share-based compensation expense. Cash operating expenses is not a measure of operating expenses as determined by GAAP.
The amounts included in the calculation of cash operating expenses were computed in
accordance with GAAP. Cash operating expenses is presented
herein
and
reconciled
to
the
GAAP
measure
of
operating
expenses.
We
use
cash
operating
expenses
as
an
indicator
of
the
Company’s
ability
to
manage
its
operating
expenses
and
cash
flows.
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
cash operating expenses to operating expenses for the three months ended March 31, 2015 and
2014.
(in thousands, except per-Boe amounts)
Three Months Ended
March 31,
2015
2014
Operating expenses
$
45,686
$
44,899
Exploration
(1,090)
(738)
Depletion, depreciation and amortization
(26,520)
(23,606)
Share-based compensation
(2,217)
(2,654)
Cash operating expenses
$
15,859
$
17,901
Cash operating expenses per Boe
$
12.32
$
16.78
First Quarter 2015 Results – May 2015 |
 Contact information
SERGEI KRYLOV
Executive Vice President & Chief Financial Officer
817.989.9000
ir@approachresources.com
www.approachresources.com |