FORT WORTH, Texas--(BUSINESS WIRE)--
Approach Resources Inc. (NASDAQ:AREX) today reported results for
fourth quarter and full-year 2015 and estimated 2015 proved reserves.
Balance Sheet Highlights
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No capital expenditures in the fourth quarter allowed for free cash
flow and debt reduction
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Reduced current liabilities from $45.2 million at 9/30/15 to $28.5
million at 12/31/15
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Reduced total debt from $515.6 million at 9/30/15 to $496.6 million at
12/31/15
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Liquidity of over $175 million at 12/31/15
Fourth Quarter 2015 Highlights
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Production was 14.5 MBoe/d, a 4% decrease from the prior-year quarter
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Revenues totaled $25.5 million, EBITDAX (non-GAAP) was $27.0 million
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Adjusted net loss (non-GAAP) was $5.0 million, or $0.12 per diluted
share
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Per-unit cash operating expenses (non-GAAP) decreased 26% from the
prior-year quarter, and 4% from third quarter 2015, to $10.01 per Boe
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No capital expenditures were incurred during the quarter
Full-Year 2015 Highlights
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Production was 15.2 MBoe/d, a 10% increase over the prior year
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Revenues were $131.3 million, EBITDAX (non-GAAP) was $123.6 million
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Adjusted net loss (non-GAAP) was $15.0 million, or $0.37 per diluted
share
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Capital expenditures of $151.2 million
2015 Proved Reserves and Operations Highlights
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Year-end 2015 proved reserves were 166.6 MMBoe, a 14% increase over
the prior year
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PV-10 (non-GAAP) was $504 million, reserve replacement ratio of 603%
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Drill-bit finding and development (non-GAAP) cost of $4.32 per Boe
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Drilled 20 horizontal wells and placed 28 horizontal wells on
production during the first eight months of 2015
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Recent horizontal Wolfcamp wells tracking 45% above typecurve
Adjusted net (loss) income, EBITDAX, cash operating expenses, PV-10
and drill-bit finding and development (“F&D”) cost are non-GAAP
measures. See “Supplemental Non-GAAP Financial and Other Measures” below
for our definitions and reconciliations of adjusted net (loss) income
and EBITDAX to net (loss) income, cash operating expenses to operating
expenses and PV-10 to the standardized measure (GAAP) and our definition
and calculation of liquidity, reserve replacement ratio and drill-bit
F&D cost.
Management Comment
Ross Craft, Approach’s Chairman and CEO commented, “2015 proved to be
another challenging year for the industry, as further deteriorating
commodity prices continued to put pressure on all North American
producers. However, despite the formidable commodity price environment,
I am pleased to report that Approach was once again able to grow annual
production and reserves to record levels, all while operating under a
significantly reduced capital budget, which speaks to the quality of our
assets and people. Importantly, we also made considerable progress
during the year toward streamlining our corporate cost structure and
further improving our industry-leading Permian Basin horizontal drilling
and completion costs to $3.7 million per well based on current AFEs. We
anticipate additional cost savings going forward.
While we remain hopeful that a correction in global supply/demand
fundamentals will begin to drive a commodity price recovery in the
second half of 2016, current signs point to continued, near-term price
weakness. With that in mind, we have established a 2016 capital budget
range of $20 million to $80 million, depending on the direction of
commodity prices. This flexible plan will allow us to target our capital
spending closer to cash flow while preserving liquidity.”
Fourth Quarter 2015 Results
Production for fourth quarter 2015 totaled 1,330 MBoe (14.5 MBoe/d),
made up of 30% oil, 32% NGLs and 38% natural gas. Average realized
commodity prices for fourth quarter 2015, before the effect of commodity
derivatives, were $37.60 per Bbl of oil, $10.20 per Bbl of NGLs and
$2.02 per Mcf of natural gas. Our average realized price, including the
effect of commodity derivatives, was $30.11 per Boe for fourth quarter
2015.
Net loss for fourth quarter 2015 was $5.8 million, or $0.14 per diluted
share, on revenues of $25.5 million. Net loss for fourth quarter 2015
also included an unrealized loss on commodity derivatives of $10.3
million, a realized gain on commodity derivatives of $14.6 million, and
a gain on debt extinguishment of $9.1 million. Excluding the unrealized
loss on commodity derivatives and gain on debt extinguishment, adjusted
net loss (non-GAAP) for fourth quarter 2015 was $5.0 million, or $0.12
per diluted share. EBITDAX (non-GAAP) for fourth quarter 2015 was $27.0
million, or $0.66 per diluted share. See “Supplemental Non-GAAP
Financial and Other Measures” below for our reconciliation of adjusted
net (loss) income and EBITDAX to net (loss) income.
Lease operating expenses averaged $5.44 per Boe. Production and ad
valorem taxes averaged $1.94 per Boe, or 10.1% of oil, NGL and gas
sales. Exploration costs were $0.17 per Boe. Cash general and
administrative costs averaged $2.63 per Boe. Depletion, depreciation and
amortization expense averaged $17.42 per Boe. Interest expense totaled
$6.4 million.
Full-Year 2015 Results
Production for 2015 increased 10% to 5,532 MBoe (15.2 MBoe/d), made up
of 34% oil, 31% NGLs and 35% natural gas. Average realized commodity
prices for 2015, before the effect of commodity derivatives, were $43.65
per Bbl of oil, $12.06 per Bbl of NGLs and $2.45 per Mcf of natural gas.
Our average realized price, including the effect of commodity
derivatives, was $33.23 per Boe for 2015.
Net loss for 2015 was $174.1 million, or $4.30 per diluted share, on
revenues of $131.3 million. Net loss for 2015 included an unrealized
loss on commodity derivatives of $33.2 million, a realized gain on
commodity derivatives of $52.5 million, impairment expense of $220.2
million, rig termination fees of $2.2 million, costs of $1.4 million
related to a reduction in our workforce, and a gain on debt
extinguishment of $10.6 million. Excluding the unrealized loss on
commodity derivatives, impairment expense, rig termination fees,
workforce reduction related costs and gain on debt extinguishment,
adjusted net loss (non-GAAP) for 2015 was $15.0 million, or $0.37 per
diluted share. EBITDAX (non-GAAP) for 2015 was $123.6 million, or $3.05
per diluted share. See “Supplemental Non-GAAP Financial and Other
Measures” below for our reconciliation of adjusted net (loss) income and
EBITDAX to net (loss) income.
Lease operating expenses averaged $5.24 per Boe. Production and ad
valorem taxes averaged $2.00 per Boe, or 8.4% of oil, NGL and gas sales.
Exploration costs were $0.80 per Boe. Cash general and administrative
costs averaged $3.68 per Boe. Depletion, depreciation and amortization
expense averaged $19.76 per Boe. Interest expense totaled $25.1 million.
Operations Update
In August 2015, we elected to temporarily suspend drilling and
completion operations to preserve capital during the commodity price
downturn. There were no wells drilled or completed in fourth quarter
2015. During 2015, we drilled a total of 20 horizontal wells and
completed 28 horizontal wells. Of these, 10 wells were drilled to the B
bench and 10 wells were drilled to the C bench. At December 31, 2015, we
had five horizontal wells waiting on completion. Wells completed during
the third quarter using our enhanced completion design continue to
outperform our current typecurve, with 150-day average production rates
tracking approximately 45% above the typecurve. We continue to analyze
production from these wells and expect to apply the enhanced completion
techniques to all wells going forward.
Fourth Quarter and Full-Year 2015 Production
Estimated fourth quarter 2015 production totaled 1,330 MBoe (14.5
MBoe/d), a 4% decrease from fourth quarter 2014. Estimated full-year
2015 production totaled 5,532 MBoe (15.2 MBoe/d), a 10% increase over
2014.
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Three Months Ended
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Twelve Months Ended
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December 31,
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December 31,
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2015
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2014
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2015
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2014
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Production:
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Oil (MBbls)
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400
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542
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1,882
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2,024
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NGLs (MBbls)
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428
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404
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1,694
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1,461
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Gas (MMcf)
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3,011
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2,656
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11,732
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9,383
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Total (MBoe)
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1,330
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1,390
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5,532
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5,049
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Total (MBoe/d)
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14.5
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15.1
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15.2
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13.8
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2015 Estimated Proved Reserves and Costs Incurred
Year-end 2015 proved reserves totaled 166.6 MMBoe, up 14% from year-end
2014 proved reserves of 146.2 MMBoe. Year-end 2015 proved reserves were
33% oil, 30% NGLs and 37% natural gas, compared to 38% oil, 28% NGLs and
34% natural gas at year-end 2014.
Proved developed reserves represent approximately 37% of total year-end
2015 proved reserves, compared to 41% at year-end 2014. At December 31,
2015, 99.9% of our proved reserves were located in our core operating
area in the southern Midland Basin. Year-end 2015 estimated proved
reserves included 154.6 MMBoe attributable to the horizontal Wolfcamp
shale play, compared to 124.8 MMBoe at year-end 2014, a 24% increase.
The table below illustrates the growing predominance of our horizontal
Wolfcamp reserves over the last three years ended December 31, 2015,
2014 and 2013.
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Proved Reserves (MBoe)
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2015
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2014
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2013
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Horizontal Wolfcamp
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Proved developed
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49,843
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40,678
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23,520
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Proved undeveloped
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104,790
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84,138
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58,073
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Total
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154,633
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124,816
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81,593
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Percent of total proved reserves
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93%
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85%
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71%
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Other Vertical
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Proved developed
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12,013
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19,542
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21,669
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Proved undeveloped
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-
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1,890
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11,399
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Total
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12,013
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21,432
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33,068
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Percent of total proved reserves
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7%
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15%
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29%
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Total proved reserves
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166,646
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146,248
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114,661
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During 2015, we recorded downward revisions totaling 8.7 MMBoe,
including the reclassification of 11.9 MMBoe of proved reserves.
Revisions also included 13 MMBoe of positive revisions resulting from
cost reductions, updated well performance and technical parameters,
offset by 9.8 MMBoe of negative revisions due to lower commodity prices.
The following table summarizes the changes in our estimated proved
reserves during 2015.
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Oil
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NGLs
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Natural Gas
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Total
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(MBbls)
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(MBbls)
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(MMcf)
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(MBoe)
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Balance – December 31, 2014
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55,338
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40,907
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300,020
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146,248
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Extensions and discoveries
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11,054
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10,630
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79,268
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34,895
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Production (1)
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(1,882
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)
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(1,694
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)
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(13,262
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)
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(5,787
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)
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Revisions
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(10,014
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)
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(357
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)
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9,962
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(8,710
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)
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Balance – December 31, 2015
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54,496
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49,486
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375,988
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166,646
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(1) Production includes 1,530 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, 2015, was $460 million. The PV-10,
or pre-tax present value of our proved reserves discounted at 10%, of
our proved reserves at December 31, 2015,was $504 million, compared to
$1.4 billion at year-end 2014. The independent engineering firm DeGolyer
and MacNaughton prepared our estimates of year-end 2015 proved reserves
and PV-10. PV-10 is a non-GAAP measure. See “Supplemental Non-GAAP
Financial and Other Measures” below for our definition of PV-10 and a
reconciliation to the standardized measure (GAAP). Estimates of year-end
2015 proved reserves and PV-10 were prepared using $50.16 per Bbl of
oil, $15.13 per Bbl of NGLs and $2.64 per MMBtu of natural gas, adjusted
for basis differentials, grade and quality.
Capital expenditures incurred during 2015 totaled $151.2 million and
included $139.1 million for drilling and completion activities, $11.4
million for infrastructure projects and equipment and $0.7 million for
lease extensions.
2016 Guidance
The table below sets forth the Company’s production and operating costs
and expenses guidance for 2016 under a $20 million capital budget
scenario. Under this plan, we would drill six and complete five wells,
with the flexibility to increase or decrease the number of drilled and
completed wells depending on market conditions.
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2016 Guidance
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Production:
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Oil (MBbls)
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1,300 – 1,400
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NGLs (MBbls)
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1,440 – 1,540
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Gas (MMcf)
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9,600 – 10,100
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Total (MBoe)
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4,340 – 4,625
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Cash operating costs (per Boe):
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Lease operating
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$
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5.00 – 6.00
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Production and ad valorem taxes
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8.0% of oil & gas revenues
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Cash general and administrative
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$
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3.50 – 4.00
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Non-cash operating costs (per Boe):
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Non-cash general and administrative
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$
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1.00 – 1.50
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Exploration
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$
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0.50 – 1.00
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Depletion, depreciation and amortization
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$
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18.00 – 20.00
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Capital expenditures (in millions)
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Approximately $20
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The table below illustrates potential activity levels and production
forecasts under various capital budget scenarios.
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D&C
Budget
($MM)
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Wells
Drilled
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Wells
Completed
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Estimated
Production
(MBoe)
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Exit-Rate
Production
Change
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$20
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6
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5
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4,471
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-19.2%
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$45
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12
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12
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4,731
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-11.1%
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$80
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24
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20
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4,805
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+1.2%
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As further discussed below under “Forward-Looking and Cautionary
Statements,” the Company’s guidance is forward-looking information that
is subject to a number of risks and uncertainties, many of which are
beyond the Company’s control. In addition, our 2016 capital budget
excludes acquisitions and lease extensions and renewals and is subject
to change depending upon a number of factors, including prevailing and
anticipated prices for oil, NGLs and natural gas, results of horizontal
drilling and completions, economic and industry conditions at the time
of drilling, the availability of sufficient capital resources for
drilling prospects, the Company’s financial results and the availability
of lease extensions and renewals on reasonable terms.
Liquidity Update
At December 31, 2015, we had a $1 billion senior secured revolving
credit facility in place. The borrowing base and lender commitment
amount were set at $450 million following the fall 2015 bank
redetermination. At December 31, 2015, our liquidity and long-term
debt-to-capital ratio were approximately $177.3 million and 45.0%,
respectively. See “Supplemental Non-GAAP Financial and Other Measures”
below for our definitions and calculation of liquidity and long-term
debt-to-capital.
Commodity Derivatives Update
We enter into commodity derivatives positions to reduce the risk of
commodity price fluctuations. The table below is a summary of our
current derivatives positions.
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Commodity and Period
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Contract
Type
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Volume Transacted
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Contract Price
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Crude Oil
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January 2016 – December 2016
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Swap
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750 Bbls/d
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$62.52/Bbl
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January 2016 – June 2016
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Swap
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1,000 Bbls/d
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$40.00/Bbl
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January 2016 – June 2016
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Swap
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500 Bbls/d
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$40.25/Bbl
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Natural Gas
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February 2016 – March 2017
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Swap
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400,000 MMBtu/month
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$2.45/MMBtu
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March 2016 – December 2016
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Swap
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200,000 MMBtu/month
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$2.93/MMBtu
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April 2017 – December 2017
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Collar
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200,000 MMBtu/month
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$2.30/MMBtu - $2.60/MMBtu
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Conference Call Information and Summary Presentation
The Company will host a conference call on Friday, March 4, 2016, at
9:00 a.m. Central Time (10:00 a.m. Eastern Time) to discuss fourth
quarter and full-year 2015 financial and operational results. 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/29285970
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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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29285970
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In addition, a fourth quarter and full-year 2015 summary presentation
will be 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 natural 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
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Twelve Months Ended
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December 31,
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December 31,
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2015
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2014
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2015
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|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
|
$
|
15,028
|
|
|
$
|
36,982
|
|
|
|
$
|
82,170
|
|
|
$
|
177,491
|
|
NGLs
|
|
|
|
|
4,370
|
|
|
|
8,512
|
|
|
|
|
20,437
|
|
|
|
41,998
|
|
Gas
|
|
|
|
|
6,094
|
|
|
|
9,576
|
|
|
|
|
28,729
|
|
|
|
39,040
|
|
Total oil, NGL and gas sales
|
|
|
|
|
25,492
|
|
|
|
55,070
|
|
|
|
|
131,336
|
|
|
|
258,529
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized gain on commodity derivatives
|
|
|
|
|
14,552
|
|
|
|
7,782
|
|
|
|
|
52,489
|
|
|
|
2,359
|
|
Total oil, NGL and gas sales including derivative impact
|
|
|
|
$
|
40,044
|
|
|
$
|
62,852
|
|
|
|
$
|
183,825
|
|
|
$
|
260,888
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
|
|
400
|
|
|
|
542
|
|
|
|
|
1,882
|
|
|
|
2,024
|
|
NGLs (MBbls)
|
|
|
|
|
428
|
|
|
|
404
|
|
|
|
|
1,694
|
|
|
|
1,461
|
|
Gas (MMcf)
|
|
|
|
|
3,011
|
|
|
|
2,656
|
|
|
|
|
11,732
|
|
|
|
9,383
|
|
Total (MBoe)
|
|
|
|
|
1,330
|
|
|
|
1,390
|
|
|
|
|
5,532
|
|
|
|
5,049
|
|
Total (MBoe/d)
|
|
|
|
|
14.5
|
|
|
|
15.1
|
|
|
|
|
15.2
|
|
|
|
13.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
|
|
$
|
37.60
|
|
|
$
|
68.17
|
|
|
|
$
|
43.65
|
|
|
$
|
87.69
|
|
NGLs (per Bbl)
|
|
|
|
|
10.20
|
|
|
|
21.04
|
|
|
|
|
12.06
|
|
|
|
28.74
|
|
Gas (per Mcf)
|
|
|
|
|
2.02
|
|
|
|
3.61
|
|
|
|
|
2.45
|
|
|
|
4.16
|
|
Total (per Boe)
|
|
|
|
$
|
19.17
|
|
|
$
|
39.63
|
|
|
|
$
|
23.74
|
|
|
$
|
51.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized gain on commodity derivatives (per Boe)
|
|
|
|
|
10.94
|
|
|
|
5.60
|
|
|
|
|
9.49
|
|
|
|
0.47
|
|
Total including derivative impact (per Boe)
|
|
|
|
$
|
30.11
|
|
|
$
|
45.23
|
|
|
|
$
|
33.23
|
|
|
$
|
51.67
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses (per Boe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
|
$
|
5.44
|
|
|
$
|
6.65
|
|
|
|
$
|
5.24
|
|
|
$
|
6.48
|
|
Production and ad valorem taxes
|
|
|
|
|
1.94
|
|
|
|
2.52
|
|
|
|
|
2.00
|
|
|
|
3.16
|
|
Exploration
|
|
|
|
|
0.17
|
|
|
|
0.17
|
|
|
|
|
0.80
|
|
|
|
0.76
|
|
General and administrative(1)
|
|
|
|
|
4.10
|
|
|
|
6.11
|
|
|
|
|
5.12
|
|
|
|
6.36
|
|
Depletion, depreciation and amortization
|
|
|
|
|
17.42
|
|
|
|
20.63
|
|
|
|
|
19.76
|
|
|
|
21.15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)Below is a summary of general and
administrative expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative – cash
component
|
|
|
|
$
|
2.63
|
|
|
$
|
4.30
|
|
|
|
$
|
3.68
|
|
|
$
|
4.73
|
|
General and administrative – noncash
component
|
|
|
|
|
1.47
|
|
|
|
1.81
|
|
|
|
|
1.44
|
|
|
|
1.63
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
APPROACH RESOURCES INC. AND SUBSIDIARIES
|
|
UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS
|
|
(In thousands, except shares and per-share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Twelve Months Ended
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
|
|
2015
|
|
|
2014
|
|
|
2015
|
|
|
2014
|
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, NGL and gas sales
|
|
|
$
|
25,492
|
|
|
$
|
55,070
|
|
|
$
|
131,336
|
|
|
$
|
258,529
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
|
7,228
|
|
|
|
9,239
|
|
|
|
28,972
|
|
|
|
32,701
|
|
|
Production and ad valorem taxes
|
|
|
|
2,583
|
|
|
|
3,505
|
|
|
|
11,085
|
|
|
|
15,934
|
|
|
Exploration
|
|
|
|
228
|
|
|
|
236
|
|
|
|
4,439
|
|
|
|
3,831
|
|
|
General and administrative
|
|
|
|
5,459
|
|
|
|
8,492
|
|
|
|
28,341
|
|
|
|
32,104
|
|
|
Termination costs
|
|
|
|
–
|
|
|
|
–
|
|
|
|
1,436
|
|
|
|
–
|
|
|
Impairment of oil and gas properties
|
|
|
|
–
|
|
|
|
–
|
|
|
|
220,197
|
|
|
|
–
|
|
|
Depletion, depreciation and amortization
|
|
|
|
23,173
|
|
|
|
28,664
|
|
|
|
109,319
|
|
|
|
106,802
|
|
|
Total expenses
|
|
|
|
38,671
|
|
|
|
50,136
|
|
|
|
403,789
|
|
|
|
191,372
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING (LOSS) INCOME
|
|
|
|
(13,179
|
)
|
|
|
4,934
|
|
|
|
(272,453
|
)
|
|
|
67,157
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
|
(6,436
|
)
|
|
|
(5,715
|
)
|
|
|
(25,066
|
)
|
|
|
(21,651
|
)
|
|
Gain on debt extinguishment
|
|
|
|
9,080
|
|
|
|
–
|
|
|
|
10,563
|
|
|
|
–
|
|
|
Equity in earnings (losses) of investee
|
|
|
|
–
|
|
|
|
5
|
|
|
|
–
|
|
|
|
(181
|
)
|
|
Realized gain on commodity derivatives
|
|
|
|
14,552
|
|
|
|
7,782
|
|
|
|
52,489
|
|
|
|
2,359
|
|
|
Unrealized (loss) gain on commodity derivatives
|
|
|
|
(10,285
|
)
|
|
|
36,907
|
|
|
|
(33,214
|
)
|
|
|
42,113
|
|
|
Other income
|
|
|
|
225
|
|
|
|
176
|
|
|
|
172
|
|
|
|
67
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(LOSS) INCOME BEFORE INCOME TAX PROVISION
|
|
|
|
(6,043
|
)
|
|
|
44,089
|
|
|
|
(267,509
|
)
|
|
|
89,864
|
|
|
INCOME TAX (BENEFIT) PROVISION:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
|
(265
|
)
|
|
|
(25
|
)
|
|
|
(265
|
)
|
|
|
(25
|
)
|
|
Deferred
|
|
|
|
(19
|
)
|
|
|
17,127
|
|
|
|
(93,140
|
)
|
|
|
33,717
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET (LOSS) INCOME
|
|
|
$
|
(5,759
|
)
|
|
$
|
26,987
|
|
|
$
|
(174,104
|
)
|
|
$
|
56,172
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS PER SHARE:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
$
|
(0.14
|
)
|
|
$
|
0.68
|
|
|
$
|
(4.30
|
)
|
|
$
|
1.43
|
|
|
Diluted
|
|
|
$
|
(0.14
|
)
|
|
$
|
0.68
|
|
|
$
|
(4.30
|
)
|
|
$
|
1.42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED AVERAGE SHARES OUTSTANDING:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
40,598,098
|
|
|
|
39,651,587
|
|
|
|
40,464,283
|
|
|
|
39,407,733
|
|
|
Diluted
|
|
|
|
40,598,098
|
|
|
|
39,651,587
|
|
|
|
40,464,283
|
|
|
|
39,419,865
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
UNAUDITED SELECTED FINANCIAL DATA
|
|
|
|
|
|
|
|
Unaudited Consolidated Balance Sheet Data
|
|
|
|
December 31,
|
|
(in thousands)
|
|
|
|
2015
|
|
|
2014
|
|
Cash and cash equivalents
|
|
|
|
$
|
600
|
|
|
$
|
432
|
|
Other current assets
|
|
|
|
|
19,838
|
|
|
|
60,647
|
|
Property and equipment, net, successful efforts method
|
|
|
|
|
1,154,546
|
|
|
|
1,331,659
|
|
Total assets
|
|
|
|
$
|
1,174,984
|
|
|
$
|
1,392,738
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
|
|
$
|
28,508
|
|
|
$
|
106,852
|
|
Long-term debt (1)
|
|
|
|
|
496,587
|
|
|
|
391,311
|
|
Other long-term liabilities
|
|
|
|
|
41,922
|
|
|
|
120,248
|
|
Stockholders’ equity
|
|
|
|
|
607,967
|
|
|
|
774,327
|
|
Total liabilities and stockholders’ equity
|
|
|
|
$
|
1,174,984
|
|
|
$
|
1,392,738
|
|
(1)
|
|
Long-term debt at December 31, 2015, is comprised of $230.3 million
in 7% senior notes due 2021 and $273 million in outstanding
borrowings under our senior secured credit facility, net of issuance
costs of $4.5 million and $2.2 million, respectively. In 2015 we
repurchased a portion of our senior notes in the open market with an
aggregate face value of $19.7 million for a purchase price of $8.8
million, including accrued interest. Long-term debt at December 31,
2014, is comprised of $250 million in 7% senior notes due 2021 and
$150 million in outstanding borrowings under our senior secured
credit facility, net of issuance costs of $5.8 million and $2.9
million, respectively.
|
|
|
|
|
|
Unaudited Consolidated Cash Flow Data
|
|
|
|
Twelve Months Ended December 31,
|
|
|
(in thousands)
|
|
|
|
2015
|
|
|
2014
|
|
|
Net cash provided (used) by:
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
|
|
$
|
102,716
|
|
|
$
|
171,604
|
|
|
Investing activities
|
|
|
|
$
|
(217,347
|
)
|
|
$
|
(377,172
|
)
|
|
Financing activities
|
|
|
|
$
|
114,799
|
|
|
$
|
147,239
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 (Loss) Income
This release contains the non-GAAP financial measures adjusted net
(loss) income and adjusted net (loss) income per diluted share, which
exclude (1) unrealized loss (gain) on commodity derivatives, (2) rig
termination fees, (3) impairment of oil and gas properties, (4)
termination costs, (5) gain on debt extinguishment, and (6) related
income tax effect. 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 (loss)
income and adjusted net (loss) income per diluted share are useful to
investors because they provide readers with a 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 (loss) income
to net (loss) income for the three and twelve months ended December 31,
2015 and 2014 (in thousands, except per-share amounts).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
Twelve Months Ended
|
|
|
|
|
|
December 31,
|
|
|
|
December 31,
|
|
|
|
|
|
2015
|
|
|
|
2014
|
|
|
|
2015
|
|
|
|
2014
|
|
|
Net (loss) income
|
|
|
$
|
(5,759
|
)
|
|
|
$
|
26,987
|
|
|
|
$
|
(174,104
|
)
|
|
|
$
|
56,172
|
|
|
Adjustments for certain items:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized loss (gain) on commodity derivatives
|
|
|
|
10,285
|
|
|
|
|
(36,907
|
)
|
|
|
|
33,214
|
|
|
|
|
(42,113
|
)
|
|
Rig termination fees
|
|
|
|
–
|
|
|
|
|
–
|
|
|
|
|
2,199
|
|
|
|
|
–
|
|
|
Impairment of oil and gas properties
|
|
|
|
–
|
|
|
|
|
–
|
|
|
|
|
220,197
|
|
|
|
|
–
|
|
|
Termination costs
|
|
|
|
–
|
|
|
|
|
–
|
|
|
|
|
1,436
|
|
|
|
|
–
|
|
|
Gain on debt extinguishment
|
|
|
|
(9,080
|
)
|
|
|
|
–
|
|
|
|
|
(10,563
|
)
|
|
|
|
–
|
|
|
Related income tax effect
|
|
|
|
(422
|
)
|
|
|
|
13,287
|
|
|
|
|
(87,348
|
)
|
|
|
|
15,161
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted net (loss) income
|
|
|
$
|
(4,976
|
)
|
|
|
$
|
3,367
|
|
|
|
$
|
(14,969
|
)
|
|
|
$
|
29,220
|
|
|
Adjusted net (loss) income per diluted share
|
|
|
$
|
(0.12
|
)
|
|
|
$
|
0.08
|
|
|
|
$
|
(0.37
|
)
|
|
|
$
|
0.74
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDAX
We define EBITDAX as net (loss) income, plus (1) exploration expense,
(2) depletion, depreciation and amortization expense, (3) share-based
compensation expense, (4) impairment of oil and gas properties, (5)
unrealized loss (gain) on commodity derivatives, (6) gain on debt
extinguishment, (7) termination costs, (8) interest expense, net, and
(9) income tax (benefit) provision. 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 (loss)
income for the three and twelve months ended December 31, 2015 and 2014
(in thousands, except per-share amounts).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Twelve Months Ended
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
|
|
2015
|
|
|
|
2014
|
|
|
|
2015
|
|
|
|
2014
|
|
|
Net (loss) income
|
|
|
|
$
|
(5,759
|
)
|
|
|
$
|
26,987
|
|
|
|
$
|
(174,104
|
)
|
|
|
$
|
56,172
|
|
|
Exploration
|
|
|
|
|
228
|
|
|
|
|
236
|
|
|
|
|
4,439
|
|
|
|
|
3,831
|
|
|
Depletion, depreciation and amortization
|
|
|
|
|
23,173
|
|
|
|
|
28,664
|
|
|
|
|
109,319
|
|
|
|
|
106,802
|
|
|
Share-based compensation
|
|
|
|
|
1,954
|
|
|
|
|
2,521
|
|
|
|
|
7,954
|
|
|
|
|
8,247
|
|
|
Impairment of oil and gas properties
|
|
|
|
|
–
|
|
|
|
|
–
|
|
|
|
|
220,197
|
|
|
|
|
–
|
|
|
Unrealized loss (gain) on commodity derivatives
|
|
|
|
|
10,285
|
|
|
|
|
(36,907
|
)
|
|
|
|
33,214
|
|
|
|
|
(42,113
|
)
|
|
Gain on debt extinguishment
|
|
|
|
|
(9,080
|
)
|
|
|
|
–
|
|
|
|
|
(10,563
|
)
|
|
|
|
–
|
|
|
Termination costs
|
|
|
|
|
–
|
|
|
|
|
–
|
|
|
|
|
1,436
|
|
|
|
|
–
|
|
|
Interest expense, net
|
|
|
|
|
6,436
|
|
|
|
|
5,715
|
|
|
|
|
25,066
|
|
|
|
|
21,651
|
|
|
Income tax (benefit) provision
|
|
|
|
|
(284
|
)
|
|
|
|
17,102
|
|
|
|
|
(93,405
|
)
|
|
|
|
33,692
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDAX
|
|
|
|
$
|
26,953
|
|
|
|
$
|
44,318
|
|
|
|
$
|
123,553
|
|
|
|
$
|
188,282
|
|
|
EBITDAX per diluted share
|
|
|
|
$
|
0.66
|
|
|
|
$
|
1.12
|
|
|
|
$
|
3.05
|
|
|
|
$
|
4.78
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Operating Expenses
We define cash operating expenses as operating expenses, excluding (1)
exploration expense, (2) depletion, depreciation and amortization
expense, (3) share-based compensation expense, (4) termination costs,
and (5) impairment of oil and gas properties. 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 table below provides a reconciliation of cash operating expenses to
operating expenses for the three and twelve months ended December 31,
2015 and 2014 (in thousands, except per-Boe amounts).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Twelve Months Ended
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
|
|
2015
|
|
|
|
2014
|
|
|
|
2015
|
|
|
|
2014
|
|
|
Operating expenses
|
|
|
|
$
|
38,671
|
|
|
|
$
|
50,136
|
|
|
|
$
|
403,789
|
|
|
|
$
|
191,372
|
|
|
Exploration
|
|
|
|
|
(228
|
)
|
|
|
|
(236
|
)
|
|
|
|
(4,439
|
)
|
|
|
|
(3,831
|
)
|
|
Depletion, depreciation and amortization
|
|
|
|
|
(23,173
|
)
|
|
|
|
(28,664
|
)
|
|
|
|
(109,319
|
)
|
|
|
|
(106,802
|
)
|
|
Share-based compensation
|
|
|
|
|
(1,954
|
)
|
|
|
|
(2,521
|
)
|
|
|
|
(7,954
|
)
|
|
|
|
(8,247
|
)
|
|
Termination costs
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
(1,436
|
)
|
|
|
|
—
|
|
|
Impairment of oil and gas properties
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
(220,197
|
)
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash operating expenses
|
|
|
|
$
|
13,316
|
|
|
|
$
|
18,715
|
|
|
|
$
|
60,444
|
|
|
|
$
|
72,492
|
|
|
Cash operating expenses per Boe
|
|
|
|
$
|
10.01
|
|
|
|
$
|
13.47
|
|
|
|
$
|
10.93
|
|
|
|
$
|
14.36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PV-10
The present value of our proved reserves, discounted at 10% (“PV-10”),
was estimated at $504 million at December 31, 2015, and was calculated
based on the first-of-the-month, 12-month average prices for oil, NGLs
and gas, of $50.16 per Bbl of oil, $15.13 per Bbl of NGLs and $2.64 per
MMBtu of natural gas, adjusted for basis differentials, grade and
quality.
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, 2015
|
|
|
PV-10
|
|
|
|
$
|
504
|
|
|
Less income taxes:
|
|
|
|
|
|
|
|
Undiscounted future income taxes
|
|
|
|
|
(307
|
)
|
|
10% discount factor
|
|
|
|
|
263
|
|
|
Future discounted income taxes
|
|
|
|
|
(44
|
)
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
|
|
$
|
460
|
|
|
|
|
|
|
|
|
|
Finding and Development (“F&D”) 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 15, 2016. 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 2015 to the
information required by paragraphs 11 and 21 of ASC 932-235:
|
|
|
|
|
|
|
|
|
Cost summary (in thousands)
|
|
|
|
|
|
|
|
Property acquisition costs
|
|
|
|
|
|
|
|
Unproved properties
|
|
|
|
$
|
653
|
|
|
Proved properties
|
|
|
|
|
–
|
|
|
Exploration costs
|
|
|
|
|
4,439
|
|
|
Development costs
|
|
|
|
|
146,237
|
|
|
Total costs incurred
|
|
|
|
$
|
151,329
|
|
|
|
|
|
|
|
|
|
|
Reserve summary (MBoe)
|
|
|
|
|
|
|
|
Balance?December 31, 2014
|
|
|
|
|
146,248
|
|
|
Extensions and discoveries
|
|
|
|
|
34,895
|
|
|
Production (1)
|
|
|
|
|
(5,787
|
)
|
|
Revisions to previous estimates
|
|
|
|
|
(8,710
|
)
|
|
Balance?December 31, 2015
|
|
|
|
|
166,646
|
|
|
|
|
|
|
|
|
|
|
Finding and development costs ($/Boe)
|
|
|
|
|
|
|
|
All-in F&D cost
|
|
|
|
$
|
5.78
|
|
|
Drill-bit F&D cost
|
|
|
|
$
|
4.32
|
|
|
|
|
|
|
|
|
|
|
Reserve replacement ratio
|
|
|
|
|
|
|
|
Extensions and discoveries / Production
|
|
|
|
|
603
|
%
|
|
|
|
|
|
|
|
|
|
(1) Production includes 1,530 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, 2015 and 2014
(in thousands).
|
|
|
|
|
Liquidity at
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
2015
|
|
|
2014
|
|
|
Borrowing base
|
|
|
|
$
|
450,000
|
|
|
$
|
450,000
|
|
|
Cash and cash equivalents
|
|
|
|
|
600
|
|
|
|
432
|
|
|
Senior secured credit facility – outstanding borrowings
|
|
|
|
|
(273,000
|
)
|
|
|
(150,000
|
)
|
|
Outstanding letters of credit
|
|
|
|
|
(325
|
)
|
|
|
(325
|
)
|
|
Liquidity
|
|
|
|
$
|
177,275
|
|
|
$
|
300,107
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2015 and 2014 (in thousands).
|
|
|
|
|
Long-Term Debt-to-Capital at
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
2015
|
|
|
2014
|
|
|
Long-term debt (1)
|
|
|
|
$
|
496,587
|
|
|
$
|
391,311
|
|
|
Total stockholders’ equity
|
|
|
|
|
607,967
|
|
|
|
774,327
|
|
|
|
|
|
|
$
|
1,104,554
|
|
|
$
|
1,165,638
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt-to-capital
|
|
|
|
|
45.0
|
%
|
|
|
33.6
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Long-term debt is net of debt issuance costs of $6.7 million and
$8.7 million at December 31, 2015 and 2014, respectively.
|
View source version on businesswire.com: http://www.businesswire.com/news/home/20160303006558/en/
Source: Approach Resources Inc.