FORT WORTH, Texas--(BUSINESS WIRE)--
Approach Resources Inc. (NASDAQ: AREX) today reported results for
fourth quarter and full-year 2013 and estimated 2013 proved reserves.
Fourth Quarter 2013 Highlights
-
Production was 11.3 MBoe/d, a 33% increase over the prior-year quarter
-
Revenues were $58.6 million, a 66% increase over the prior-year quarter
-
Net income was $64.3 million, or $1.65 per diluted share
-
Adjusted net income was $8 million, or $0.20 per diluted share
-
EBITDAX was a quarterly record of $41.1 million, or $1.05 per diluted
share, and up 99% over the prior-year quarter
Full-Year 2013 Highlights
-
Production was 9.4 MBoe/d, a 19% increase over the prior year
-
Revenues were $181.3 million, a 41% increase over the prior year
-
Net income was $72.3 million, or $1.85 per diluted share
-
Adjusted net income was $18 million, or $0.46 per diluted share
-
EBITDAX was an annual record of $127.8 million, or $3.28 per diluted
share, and up 54% over the prior year
2013 Proved Reserves Highlights
-
Year-end 2013 proved reserves were 114.7 MMBoe, a 20% increase over
year-end 2012 proved reserves
-
PV-10 was $1.1 billion, a 36% increase
-
Reserve replacement ratio of 776%
-
Drill-bit finding and development cost of $10.63 per Boe
Adjusted net income, EBITDAX, PV-10, reserve replacement ratio and
drill-bit finding and development (“F&D”) cost are non-GAAP measures.
See “Supplemental Non-GAAP Measures” below for our definitions and
reconciliations of adjusted net income and EBITDAX to net income and
PV-10 to the Standardized Measure (GAAP) and our definition and
calculation of reserve replacement ratio and drill-bit F&D cost.
Management Comment
J. Ross Craft
, Approach’s President and Chief Executive officer,
commented, “Our fourth quarter and full-year 2013 results demonstrate
significant progress in transitioning Approach’s strategy from drilling
vertical gas wells to leading the horizontal development of the
oil-rich, multi-zone Wolfcamp shale. Since 2011, when we began drilling
horizontal Wolfcamp wells, we have tripled oil production, increased oil
reserves by more than 2.5 times and increased our horizontal Wolfcamp
reserves by five times. We believe this substantial growth underscores
the future potential from the horizontal Wolfcamp shale oil play.
“We also generated substantial margin improvement due to our oil
production growth and lower cost structure. In addition, we made
consistent strides against our horizontal well cost target in 2013. We
are capturing many cost-saving benefits and efficiencies from our field
infrastructure and recycling systems, which are contributing to our
operational momentum as we begin 2014. We also advanced delineation of
the Wolfcamp C bench and our understanding of stacked wellbore
development in 2013. We now consider the Wolfcamp C bench in full
development with our recent three-well pad completion, which also
supports our field development outlook for the horizontal Wolfcamp play.”
Fourth Quarter 2013 Results
Production for fourth quarter 2013 totaled 1,041 MBoe (11.3 MBoe/d),
made up of 46% oil, 26% NGLs and 28% natural gas. Average realized
commodity prices for fourth quarter 2013, before the effect of commodity
derivatives, were $91.34 per Bbl of oil, $31.41 per Bbl of NGLs and
$3.77 per Mcf of natural gas. Our average realized price, including the
effect of commodity derivatives, was $56.46 per Boe for fourth quarter
2013.
Net income for fourth quarter 2013 was $64.3 million, or $1.65 per
diluted share, on revenues of $58.6 million. During fourth quarter 2013,
Approach, together with our partner in Wildcat Permian Services LLC
(“Wildcat”), completed the sale of all of the equity interests of
Wildcat for a purchase price of $210 million. Wildcat owned and operated
an oil pipeline system in Crockett and Reagan Counties, Texas. Net
income for fourth quarter 2013 included a pre-tax gain of $90.7 million
related to the sale of our interest in the Wildcat oil pipeline, subject
to normal post-closing adjustments.
Net income for fourth quarter 2013 also included an unrealized loss on
commodity derivatives of $1.3 million and a realized gain on commodity
derivatives of $0.2 million. Excluding the unrealized loss on commodity
derivatives, gain on the sale of our interest in Wildcat and related
income taxes, adjusted net income (non-GAAP) for fourth quarter 2013 was
$8 million, or $0.20 per diluted share. EBITDAX (non-GAAP) for fourth
quarter 2013 was $41.1 million, or $1.05 per diluted share. See
“Supplemental Non-GAAP Financial and Other Measures” below for our
reconciliation of adjusted net income and EBITDAX to net income.
Lease operating expenses averaged $5.19 per Boe. Production and ad
valorem taxes averaged $3.89 per Boe, or 6.9% of oil, NGL and gas sales.
Exploration costs were $0.22 per Boe. General and administrative costs
averaged $8.37 per Boe. Depletion, depreciation and amortization expense
averaged $21.14 per Boe. Interest expense totaled $5.2 million.
Full-Year 2013 Results
Production for 2013 totaled 3,424 MBoe (9.4 MBoe/d), made up of 42% oil,
28% NGLs and 30% natural gas. Average realized commodity prices for
2013, before the effect of commodity derivatives, were $90.70 per Bbl of
oil, $29.57 per Bbl of NGLs and $3.60 per Mcf of natural gas. Our
average realized price, including the effect of commodity derivatives,
was $52.64 per Boe for 2013.
Net income for 2013 was $72.3 million, or $1.85 per diluted share, on
revenues of $181.3 million. Net income for 2013 included an unrealized
loss on commodity derivatives of $4.6 million, a realized loss on
commodity derivatives of $1 million and a gain on the sale of our
interest in Wildcat of $90.7 million. Excluding the unrealized loss on
commodity derivatives, gain on the sale of our interest in Wildcat and
related income taxes, adjusted net income (non-GAAP) for 2013 was $18
million, or $0.46 per diluted share. EBITDAX (non-GAAP) for 2013 was
$127.8 million, or $3.28 per diluted share. See “Supplemental Non-GAAP
Financial and Other Measures” below for our reconciliation of adjusted
net income and EBITDAX to net income.
Lease operating expenses averaged $5.59 per Boe. Production and ad
valorem taxes averaged $3.75 per Boe, or 7.1% of oil, NGL and gas sales.
Exploration costs were $0.65 per Boe. General and administrative costs
averaged $7.75 per Boe. Depletion, depreciation and amortization expense
averaged $22.48 per Boe. Interest expense totaled $14.1 million.
Operations Update
During fourth quarter 2013, we drilled 15 horizontal wells and completed
14 horizontal wells. During 2013, we drilled a total of 45 horizontal
wells and completed 40 horizontal wells. At December 31, 2013, we had
nine horizontal wells waiting on completion. The average initial 24-hour
rate for wells completed during fourth quarter 2013 was 766 Boe/d (64%
oil), excluding one short-lateral horizontal well.
During fourth quarter 2013, we completed a three-well, multi-bench pad
in central Project Pangea. The pad includes two Wolfcamp B bench wells,
the Baker B 232HB (6,500 feet lateral) and the Baker B 238HB (6,902 feet
lateral), and a Wolfcamp C bench well, the Baker B 234HC (6,132 feet
lateral), spaced approximately 660 feet apart in the same bench and
approximately 540 feet apart in the adjacent bench. The Wolfcamp C bench
well flowed at an initial 24-hour rate of 970 Boe/d (81% oil). The
Wolfcamp B bench wells flowed at initial 24-hour rates of 928 Boe/d (70%
oil) and 843 Boe/d (49% oil), respectively.
2013 Estimated Proved Reserves and Costs Incurred
Year-end 2013 proved reserves totaled 114.7 MMBoe, up 20% from year-end
2012 proved reserves of 95.5 MMBoe. Our proved oil reserves increased
24% to 46.1 MMBbls, compared to year-end 2012 proved oil reserves of
37.3 MMBbls. Year-end 2013 proved reserves were 40% oil, 29% NGLs and
31% natural gas, compared to 39% oil, 30% NGLs and 31% natural gas at
year-end 2012.
Proved developed reserves represent approximately 39% of total year-end
2013 proved reserves, up from 34% at year-end 2012. At December 31,
2013, 99.9% of our proved reserves were located in our core operating
area in the southern Midland Basin.
The increase in year-end 2013 estimated proved reserves is primarily a
result of our horizontal development project in the Wolfcamp shale oil
play. Year-end 2013 estimated proved reserves included 81.6 MMBoe
attributable to the horizontal Wolfcamp shale play, compared to 53.8
MMBoe at year-end 2012, representing a 52% increase.
The table below summarizes our estimated proved reserves attributable to
the horizontal Wolfcamp shale oil play, compared to our estimated proved
reserves attributable to vertical development for the years ended
December 31, 2013, 2012 and 2011.
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Proved Reserves (MBoe)
|
|
|
|
2013
|
|
2012
|
|
2011
|
|
Horizontal Wolfcamp
|
|
|
|
|
|
|
|
Proved developed
|
|
23,520
|
|
10,439
|
|
3,362
|
|
Proved undeveloped
|
|
58,073
|
|
43,342
|
|
13,337
|
|
Total
|
|
81,593
|
|
53,781
|
|
16,699
|
|
Percent of total proved reserves
|
|
71%
|
|
56%
|
|
22%
|
|
|
|
|
|
|
|
|
|
Other Vertical
|
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|
|
|
|
|
|
Proved developed
|
|
21,669
|
|
22,336
|
|
30,249
|
|
Proved undeveloped
|
|
11,399
|
|
19,362
|
|
30,027
|
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Total
|
|
33,068
|
|
41,698
|
|
60,276
|
|
Percent of total proved reserves
|
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29%
|
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44%
|
|
78%
|
|
|
|
|
|
|
|
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Total proved reserves
|
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114,661
|
|
95,479
|
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76,975
|
|
|
|
|
|
|
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|
During 2013, we recorded downward revisions totaling 4.7 MMBoe.
Revisions included the reclassification of 7.8 MMBoe of proved
undeveloped reserves to probable undeveloped, partially offset by 3.1
MMBoe of positive revisions attributable to natural gas that will be
produced and used as field fuel. The proved undeveloped reserves
reclassified as probable undeveloped are attributable to vertical Canyon
locations in Project Pangea that we do not plan to drill within five
years from their initial booking.
The following table summarizes the changes in our estimated proved
reserves during 2013.
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Oil
(MBbl)
|
|
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NGLs
(MBbl)
|
|
|
Natural Gas
(MMcf)
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|
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Total
(MBoe)
|
|
|
Balance – December 31, 2012
|
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37,252
|
|
|
29,100
|
|
|
174,760
|
|
|
95,479
|
|
|
Extensions and discoveries
|
|
14,252
|
|
|
6,531
|
|
|
38,993
|
|
|
27,282
|
|
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Acquisition
|
|
62
|
|
|
14
|
|
|
197
|
|
|
109
|
|
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Production (1)
|
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(1,444
|
)
|
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(951
|
)
|
|
(6,737
|
)
|
|
(3,517
|
)
|
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Revisions
|
|
(4,055
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)
|
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(2,102
|
)
|
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8,789
|
|
|
(4,692
|
)
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|
|
|
|
|
|
|
|
|
|
|
|
|
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Balance – December 31, 2013
|
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46,067
|
|
|
32,593
|
|
|
216,002
|
|
|
114,661
|
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|
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|
|
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(1) Production includes 560 MMcf related to field fuel.
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Our preliminary, unaudited estimate of the standardized after-tax
measure of discounted future net cash flows (“Standardized Measure”) of
our proved reserves at December 31, 2013, was $676.3 million. The PV-10,
or pre-tax present value of our proved reserves discounted at 10%, of
our proved reserves at December 31, 2013,was $1.1 billion, compared to
$830.9 million at year-end 2012. The independent engineering firm
DeGolyer and MacNaughton prepared our estimates of year-end 2013 proved
reserves and PV-10. PV-10 is a non-GAAP measure. See “Supplemental
Non-GAAP Measures” below for our definition of PV-10 and a
reconciliation to the Standardized Measure (GAAP). Estimates of year-end
2013 proved reserves and PV-10 were prepared using $97.28 per Bbl of
oil, $30.16 per Bbl of NGLs and $3.66 per MMBtu of natural gas.
Preliminary, unaudited costs incurred during 2013 totaled $297 million
and included $250 million for drilling and completion activities, $38
million for pipeline and infrastructure projects, $8.3 million for
property and acreage acquisitions and lease extensions and $0.7 million
for 3-D seismic data acquisition.
Liquidity Update
At December 31, 2013, we had a $500 million revolving credit facility
with a $350 million borrowing base and no outstanding borrowings. At
December 31, 2013, our liquidity and long-term debt-to-capital ratio
were approximately $408.4 million and 26%, respectively.
Conference Call Information and Summary Presentation
The Company will host a conference call on Tuesday, February 25, 2014,
at 10:00 a.m. Central Time (11:00 a.m. Eastern Time) to discuss
financial and operational results for the fourth quarter and full-year
2013. Those wishing to listen to the conference call, may do so by
visiting the Events page under the Investor Relations section of the
Company’s website, www.approachresources.com,
or by phone:
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Dial in:
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(877) 201-0168
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Intl. dial in:
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(647) 788-4901
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Passcode:
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Approach / 93847436
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A replay of the call will be available on the Company’s website or by
dialing:
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Dial in:
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(855) 859-2056
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Passcode:
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93847436
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In addition, a fourth quarter and full-year 2013 summary presentation is
available on the Company’s website.
About Approach Resources
Approach Resources Inc. is an independent energy company focused
on the exploration, development, production and acquisition of
unconventional oil and gas reserves in the Midland Basin of the greater
Permian Basin in West Texas. For more information about the Company,
please visit www.approachresources.com.
Please note that the Company routinely posts important information about
the Company under the Investor Relations section of its website.
This press release 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 press release 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 press release
specifically include expectations of anticipated financial and operating
results. These statements are based on certain assumptions made
by the Company based on management’s experience, perception of
historical trends and technical analyses, current conditions,
anticipated future developments and other factors believed to be
appropriate and reasonable by management. When used in this press
release, the words “will,” “potential,” “believe,” “estimate,” “intend,”
“expect,” “may,” “should,” “anticipate,” “could,” “plan,” “predict,”
“project,” “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. Further information on such assumptions, risks and
uncertainties is available in the Company’s Securities and Exchange
Commission (“SEC”) filings. The Company’s SEC filings are
available on the Company’s website at www.approachresources.com.
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.
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UNAUDITED RESULTS OF OPERATIONS
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Three Months Ended
December 31,
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Twelve Months Ended
December 31,
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|
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2013
|
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2012
|
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2013
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2012
|
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|
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Revenues (in thousands):
|
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|
|
|
|
|
|
|
|
|
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|
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Oil
|
|
$
|
43,421
|
|
|
$
|
23,398
|
|
|
$
|
130,971
|
|
|
$
|
82,087
|
|
|
NGLs
|
|
|
8,421
|
|
|
|
7,014
|
|
|
|
28,103
|
|
|
|
30,811
|
|
|
Gas
|
|
|
6,723
|
|
|
|
4,897
|
|
|
|
22,228
|
|
|
|
15,994
|
|
|
Total oil, NGL and gas sales
|
|
58,565
|
|
|
35,309
|
|
|
181,302
|
|
|
128,892
|
|
|
|
|
|
|
|
|
|
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|
|
|
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|
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Realized gain (loss) on commodity derivatives
|
|
199
|
|
|
(408
|
)
|
|
(1,048
|
)
|
|
(108
|
)
|
|
Total oil, NGL and gas sales including derivative impact
|
|
$
|
58,764
|
|
|
$
|
34,901
|
|
|
$
|
180,254
|
|
|
$
|
128,784
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
475
|
|
|
299
|
|
|
1,444
|
|
|
969
|
|
|
NGLs (MBbls)
|
|
268
|
|
|
232
|
|
|
951
|
|
|
904
|
|
|
Gas (MMcf)
|
|
1,784
|
|
|
1,522
|
|
|
6,177
|
|
|
6,089
|
|
|
Total (MBoe)
|
|
1,041
|
|
|
784
|
|
|
3,424
|
|
|
2,888
|
|
|
Total (MBoe/d)
|
|
11.3
|
|
|
8.5
|
|
|
9.4
|
|
|
7.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
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Average prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
91.34
|
|
|
$
|
78.27
|
|
|
$
|
90.70
|
|
|
$
|
84.70
|
|
|
NGLs (per Bbl)
|
|
|
31.41
|
|
|
|
30.27
|
|
|
|
29.57
|
|
|
|
34.09
|
|
|
Gas (per Mcf)
|
|
|
3.77
|
|
|
|
3.22
|
|
|
|
3.60
|
|
|
|
2.63
|
|
|
Total (per Boe)
|
|
$
|
56.27
|
|
|
$
|
45.02
|
|
|
$
|
52.95
|
|
|
$
|
44.63
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized gain (loss) on commodity derivatives (per Boe)
|
|
0.19
|
|
|
(0.52
|
)
|
|
(0.31
|
)
|
|
(0.03
|
)
|
|
Total including derivative impact (per Boe)
|
|
$
|
56.46
|
|
|
$
|
44.50
|
|
|
$
|
52.64
|
|
|
$
|
44.60
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses (per Boe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
$
|
5.19
|
|
|
$
|
7.29
|
|
|
$
|
5.59
|
|
|
$
|
6.58
|
|
|
Production and ad valorem taxes
|
|
3.89
|
|
|
3.12
|
|
|
3.75
|
|
|
3.20
|
|
|
Exploration
|
|
0.22
|
|
|
2.72
|
|
|
0.65
|
|
|
1.58
|
|
|
General and administrative
|
|
8.37
|
|
|
10.79
|
|
|
7.75
|
|
|
8.62
|
|
|
Depletion, depreciation and amortization
|
|
21.14
|
|
|
22.99
|
|
|
22.48
|
|
|
20.91
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
APPROACH RESOURCES INC. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except shares and per-share amounts)
|
|
|
|
|
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|
|
|
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|
|
Three Months Ended
|
|
Twelve Months Ended
|
|
|
|
|
December 31,
|
|
December 31,
|
|
|
|
|
2013
|
|
2012
|
|
2013
|
|
2012
|
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, NGL and gas sales
|
|
$
|
58,565
|
|
$
|
35,309
|
|
$
|
181,302
|
|
$
|
128,892
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
5,406
|
|
|
5,716
|
|
|
19,152
|
|
|
19,002
|
|
|
Production and ad valorem taxes
|
|
|
4,049
|
|
|
2,448
|
|
|
12,840
|
|
|
9,255
|
|
|
Exploration
|
|
|
228
|
|
|
2,131
|
|
|
2,238
|
|
|
4,550
|
|
|
General and administrative
|
|
|
8,714
|
|
|
8,455
|
|
|
26,524
|
|
|
24,903
|
|
|
Depletion, depreciation and amortization
|
|
|
22,005
|
|
|
18,027
|
|
|
76,956
|
|
|
60,381
|
|
|
Total expenses
|
|
|
40,402
|
|
|
36,777
|
|
|
137,710
|
|
|
118,091
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING INCOME (LOSS)
|
|
|
18,163
|
|
|
(1,468
|
)
|
|
43,592
|
|
|
10,801
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
(5,225
|
)
|
|
(926
|
)
|
|
(14,084
|
)
|
|
(4,737
|
)
|
|
Equity in (losses) earnings of investee
|
|
|
(4
|
)
|
|
(108
|
)
|
|
156
|
|
|
(108
|
)
|
|
Gain on sale of equity method investment
|
|
|
90,743
|
|
|
—
|
|
|
90,743
|
|
|
—
|
|
|
Realized gain (loss) on commodity derivatives
|
|
|
199
|
|
|
(408
|
)
|
|
(1,048
|
)
|
|
(108
|
)
|
|
Unrealized (loss) gain on commodity derivatives
|
|
|
(1,348
|
)
|
|
1,292
|
|
|
(4,596
|
)
|
|
3,874
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME (LOSS) BEFORE INCOME TAX PROVISION (BENEFIT)
|
|
|
102,528
|
|
|
(1,618
|
)
|
|
114,763
|
|
|
9,722
|
|
|
INCOME TAX PROVISION (BENEFIT):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
429
|
|
|
—
|
|
|
429
|
|
|
—
|
|
|
Deferred
|
|
|
37,778
|
|
|
(781
|
)
|
|
42,078
|
|
|
3,338
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME (LOSS)
|
|
$
|
64,321
|
|
$
|
(837
|
)
|
$
|
72,256
|
|
$
|
6,384
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS (LOSS) PER SHARE:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
1.65
|
|
$
|
(0.02
|
)
|
$
|
1.85
|
|
$
|
0.18
|
|
|
Diluted
|
|
$
|
1.65
|
|
$
|
(0.02
|
)
|
$
|
1.85
|
|
$
|
0.18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED AVERAGE SHARES OUTSTANDING:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
39,047,495
|
|
|
38,862,091
|
|
|
38,997,815
|
|
|
34,965,182
|
|
|
Diluted
|
|
|
39,067,553
|
|
|
38,862,091
|
|
|
39,019,149
|
|
|
35,030,323
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
UNAUDITED SELECTED FINANCIAL DATA
|
|
|
|
|
|
Unaudited Consolidated Balance Sheet Data
|
|
December 31,
|
|
(in thousands)
|
|
2013
|
|
2012
|
|
Cash and cash equivalents
|
|
$
|
58,761
|
|
$
|
767
|
|
Restricted cash
|
|
|
7,350
|
|
|
—
|
|
Other current assets
|
|
|
24,302
|
|
|
14,889
|
|
Property and equipment, net, successful efforts method
|
|
|
1,047,030
|
|
|
828,467
|
|
Equity method investment
|
|
|
—
|
|
|
9,892
|
|
Other assets
|
|
|
8,041
|
|
|
1,724
|
|
Total assets
|
|
$
|
1,145,484
|
|
$
|
855,739
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
$
|
84,441
|
|
$
|
60,247
|
|
Long-term debt (1)
|
|
|
250,000
|
|
|
106,000
|
|
Other long-term liabilities
|
|
|
100,548
|
|
|
56,024
|
|
Stockholders’ equity
|
|
|
710,495
|
|
|
633,468
|
|
Total liabilities and stockholders’ equity
|
|
$
|
1,145,484
|
|
$
|
855,739
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Long-term debt at December 31, 2013, is comprised of $250 million in
7% senior notes. Long-term debt at December 31, 2012, is comprised
of borrowings under our credit facility.
|
|
Unaudited Consolidated Cash Flow Data
|
|
Twelve Months Ended December 31,
|
|
|
(in thousands)
|
|
2013
|
|
2012
|
|
|
Net cash provided (used) by:
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
125,580
|
|
$
|
90,585
|
|
|
Investing activities
|
|
$
|
(203,397
|
)
|
$
|
(307,414
|
)
|
|
Financing activities
|
|
$
|
135,811
|
|
$
|
217,295
|
|
|
|
|
|
|
|
|
|
|
Supplemental Non-GAAP Financial and Other Measures
This release contains certain financial measures that are non-GAAP
measures. We have provided reconciliations below of the non-GAAP
financial measures to the most directly comparable GAAP financial
measures and on the Non-GAAP Financial Information page in the Investor
Relations section of our website at www.approachresources.com.
Adjusted Net Income
This release contains the non-GAAP financial measures adjusted net
income and adjusted net income per diluted share, which excludes an
unrealized loss (gain) on commodity derivatives, gain on the sale of our
equity method investment and related income taxes. 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 table below provides a reconciliation of adjusted net income (loss)
to net income (loss) for the three and twelve months ended December 31,
2013 and 2012 (in thousands, except per-share amounts).
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
December 31,
|
|
|
Twelve Months Ended
December 31,
|
|
|
|
|
2013
|
|
2012
|
|
2013
|
|
2012
|
|
Net income (loss)
|
|
$
|
64,321
|
|
|
$
|
(837
|
)
|
|
$
|
72,256
|
|
|
$
|
6,384
|
|
|
Adjustments for certain items:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized loss (gain) on commodity derivatives
|
|
|
1,348
|
|
|
|
(1,292
|
)
|
|
|
4,596
|
|
|
|
(3,874
|
)
|
|
Gain on sale of equity method investment
|
|
|
(90,743
|
)
|
|
|
—
|
|
|
|
(90,743
|
)
|
|
|
—
|
|
|
Related income tax effect
|
|
|
33,076
|
|
|
|
439
|
|
|
|
31,874
|
|
|
|
1,317
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted net income (loss)
|
|
$
|
8,002
|
|
|
$
|
(1,690
|
)
|
|
$
|
17,983
|
|
|
$
|
3,827
|
|
|
Adjusted net income (loss) per diluted share
|
|
$
|
0.20
|
|
|
$
|
(0.04
|
)
|
|
$
|
0.46
|
|
|
$
|
0.11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDAX
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, net, 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 table below provides a reconciliation of EBITDAX to net income
(loss) for the three and twelve months ended December 31, 2013 and 2012
(in thousands, except per-share amounts).
|
|
|
|
|
|
|
|
|
Three Months Ended
December 31,
|
|
Twelve Months Ended
December 31,
|
|
|
|
2013
|
|
2012
|
|
2013
|
|
2012
|
|
Net income (loss)
|
|
$
|
64,321
|
|
|
$
|
(837
|
)
|
|
$
|
72,256
|
|
|
$
|
6,384
|
|
|
Exploration
|
|
|
228
|
|
|
|
2,131
|
|
|
|
2,238
|
|
|
|
4,550
|
|
|
Gain on sale of equity method investment
|
|
|
(90,743
|
)
|
|
|
—
|
|
|
|
(90,743
|
)
|
|
|
—
|
|
|
Depletion, depreciation and amortization
|
|
|
22,005
|
|
|
|
18,027
|
|
|
|
76,956
|
|
|
|
60,381
|
|
|
Share-based compensation
|
|
|
512
|
|
|
|
2,472
|
|
|
|
5,901
|
|
|
|
7,465
|
|
|
Unrealized loss (gain) on commodity derivatives
|
|
|
1,348
|
|
|
|
(1,292
|
)
|
|
|
4,596
|
|
|
|
(3,874
|
)
|
|
Interest expense, net
|
|
|
5,225
|
|
|
|
926
|
|
|
|
14,084
|
|
|
|
4,737
|
|
|
Income tax provision (benefit)
|
|
|
38,207
|
|
|
|
(781
|
)
|
|
|
42,507
|
|
|
|
3,338
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDAX
|
|
$
|
41,103
|
|
|
$
|
20,646
|
|
|
$
|
127,795
|
|
|
$
|
82,981
|
|
|
EBITDAX per diluted share
|
|
$
|
1.05
|
|
|
$
|
0.53
|
|
|
$
|
3.28
|
|
|
$
|
2.37
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PV-10
The present value of our proved reserves, discounted at 10% (“PV-10”),
was estimated at $1.1 billion at December 31, 2013, and was calculated
based on the first-of-the-month, twelve-month average prices for oil,
NGLs and gas, of $97.28 per Bbl of oil, $30.16 per Bbl of NGLs and $3.66
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 table below 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, 2013
|
|
|
PV-10
|
|
$
|
1,132
|
|
|
Less income taxes:
|
|
|
|
|
|
Undiscounted future income taxes
|
|
|
(919
|
)
|
|
10% discount factor
|
|
|
463
|
|
|
Future discounted income taxes
|
|
|
(456
|
)
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
676
|
|
|
|
|
|
|
|
Finding and Development Costs
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 the above measures of 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 or before March 3, 2014. 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 table below reconciles our estimated F&D costs for 2013 to the
information required by paragraphs 11 and 21 of ASC 932-235:
|
|
|
|
|
|
|
Cost summary (in thousands)
|
|
|
|
|
|
Property acquisition costs
|
|
|
|
|
|
Unproved properties
|
|
$
|
5,857
|
|
|
Proved properties
|
|
|
1,000
|
|
|
Exploration costs
|
|
|
2,238
|
|
|
Development costs
|
|
|
287,898
|
|
|
Total costs incurred
|
|
$
|
296,993
|
|
|
|
|
|
|
|
|
Reserve summary (MBoe)
|
|
|
|
|
|
Balance?December 31, 2012
|
|
|
95,479
|
|
|
Extensions and discoveries
|
|
|
27,282
|
|
|
Acquisition
|
|
|
109
|
|
|
Production (1)
|
|
|
(3,517
|
)
|
|
Revisions to previous estimates
|
|
|
(4,692
|
)
|
|
Balance?December 31, 2013
|
|
|
114,661
|
|
|
|
|
|
|
|
|
Finding and development costs ($/Boe)
|
|
|
|
|
|
All-in F&D cost
|
|
$
|
13.08
|
|
|
Drill-bit F&D cost
|
|
$
|
10.63
|
|
|
|
|
|
|
|
|
Reserve replacement ratio
|
|
|
|
|
|
Drill-bit
|
|
|
776
|
%
|
|
(Extensions and discoveries / Production)
|
|
|
|
|
|
|
|
|
|
|
|
(1) Production includes 560 MMcf related to field fuel.
|
|
|
|
|
|
|
|
Liquidity
Liquidity 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. However, this measurement has limitations.
This measurement 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. This measurement 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, 2013 and 2012
(in thousands).
|
|
|
Liquidity at
December 31,
|
|
|
|
|
2013
|
|
|
2012
|
|
|
Borrowing base
|
|
$
|
350,000
|
|
|
$
|
280,000
|
|
|
Cash and cash equivalents
|
|
|
58,761
|
|
|
|
767
|
|
|
Outstanding letters of credit
|
|
|
(325
|
)
|
|
|
(325
|
)
|
|
Credit facility
|
|
|
—
|
|
|
|
(106,000
|
)
|
|
Liquidity
|
|
$
|
408,436
|
|
|
$
|
174,442
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term Debt-to-Capital
Long-term debt-to-capital ratio is calculated 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, 2013 and 2012 (in thousands).
|
|
|
|
|
|
|
|
Long-Term Debt-to-Capital at
December 31,
|
|
|
|
|
2013
|
|
|
2012
|
|
|
Long-term debt (1)
|
|
$
|
250,000
|
|
|
$
|
106,000
|
|
|
Total stockholders’ equity
|
|
|
710,495
|
|
|
|
633,468
|
|
|
|
|
$
|
960,495
|
|
|
$
|
739,468
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt-to-capital
|
|
|
26.0
|
%
|
|
|
14.3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Long-term debt at December 31, 2013, is comprised of $250 million in
7% senior notes. Long-term debt at December 31, 2012, is comprised
of borrowings under our credit facility.
|
Source: Approach Resources Inc.